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enSmaller, Cheaper, and More Resilienthttp://www.fortnightly.com/fortnightly/2013/04/smaller-cheaper-and-more-resilient
<div class="field field-name-field-import-deck field-type-text-long field-label-inline clearfix"><div class="field-label">Deck:&nbsp;</div><div class="field-items"><div class="field-item even"><p>The rationale for microgrids.</p>
</div></div></div><div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Edward N. Krapels and Clarke Bruno</p>
</div></div></div><div class="field field-name-field-import-bio field-type-text-long field-label-inline clearfix"><div class="field-label">Author Bio:&nbsp;</div><div class="field-items"><div class="field-item even"><p><b>Edward N. Krapels</b> is the founder and a director of Anbaric, a project development company that specializes in large-scale electric transmission systems and small, medium, and large-scale microgrids. His article, “<a href="http://www.fortnightly.com/fortnightly/2013/02/busting-transmission-trusts" target="_self">Busting the Transmission Trusts</a>,” appeared in <i>Fortnightly’s</i> February 2013 issue. <b>Clarke Bruno</b> oversees Anbaric’s legal affairs and projects in the Mid-Atlantic region. He served as counsel to New Jersey Gov. Corzine, and was New York City senior attorney.</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - April 2013</div></div></div><div class="field field-name-field-import-image field-type-image field-label-above"><div class="field-label">Image:&nbsp;</div><div class="field-items"><div class="field-item even"><img src="http://www.fortnightly.com/sites/default/files/1304-BIZ-fig1.jpg" width="1362" height="802" alt="Figure 1 - Microgrid Capacity by Region" title="Figure 1 - Microgrid Capacity by Region" /></div><div class="field-item odd"><img src="http://www.fortnightly.com/sites/default/files/1304-BIZ-fig2.jpg" width="1362" height="802" alt="Figure 2 - Microgrid Capacity by Market Segment" title="Figure 2 - Microgrid Capacity by Market Segment" /></div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p>Hurricane Sandy’s impact in New York City, Long Island, and New Jersey revealed what industry experts have long known: utilities and their regulators have underinvested in the nation’s electricity infrastructure, creating a grid that is more unreliable than a modern economy needs. Sandy’s aftermath—with long delays in restoring power, communication lines out, world-class hospitals evacuating patients, sewage treatment plants dumping waste into waterways—underscored that the grid’s one-size-fits-all standard of reliability lacks justification in a world where some services are more important than others. The primacy of emergency services aside, many believe that we also need to re-evaluate how society prioritizes investment of rate-payer dollars to operate, restore, plan, and build the transmission and distribution components of the electric system.</p>
<p>While the grid has suffered from underinvestment, the technology sector has undergone revolutions in cellular communications, microprocessor capability, and Internet connectivity. These revolutions have enabled the development of microgrids—small-scale electricity systems for one or more large users, which combine efficient generation of power with its carefully monitored use, with demand response (DR) and energy efficient technologies, in a single geographic location. These microgrids operate in parallel with or islanded from the larger grid.</p>
<p>More importantly, microgrids can provide what the public now seeks uninterrupted service for critical institutions and key components of infrastructure even when power is lost to the larger grid. They also bring competition’s creative forces to the electricity grid, which has long suffered a dearth of innovation.</p>
<p>In a region rich in microgrids, critical institutions will remain operational during blackouts, renewables will be deployed with ease, emissions will decline per unit of power used, and the grid and institutions that depend on it will each become more efficient and more resilient.</p>
<h4>Microgrids and Macro Benefits</h4>
<p>Microgrids enable large public or private institutions—hospitals, water and sewer treatment plants, universities, economic centers, shelters, and housing complexes—to obtain a secure supply of power or to restore it more quickly in the event of a blackout. When the larger grid loses power, institutions with microgrids can remain operational for weeks. Microgrids also enable host institutions to manage their own electricity use and reduce costs. Microgrids also can benefit the overall utility grid by providing increased efficiency and reducing operational and capital expenses for some sites that are costlier to serve than the average customer site. And microgrids can benefit the public, by improving the ability to maintain critical operations.</p>
<p>A growing number of world-class microgrids exist today in the United States and across the globe. Universities, hospitals, and other institutions with a public service mission are increasingly deploying microgrids. The potential of microgrids was illustrated during the 2011 earthquake and tsunami in Japan, when amidst extraordinary devastation, the Sendai 1-MW microgrid at Tohoku Fukushi University operated for two days in islanded mode while the surrounding region was without power.</p>
<p>Figures 1 and 2 portray the regional and host institution characteristics of microgrids worldwide. The majority are found in North America; the plurality are found on campuses.</p>
<p>Microgrids will increasingly be deployed to capture the benefits of solar energy, particularly in those regions where the cost of generation from photovoltaics (PV) is approaching grid parity. The networked energy management and storage capability of microgrids enable them to take full advantage of this generation technology.</p>
<h4>Operations, Revenues, and Siting</h4>
<p>Institutions and other customers deploy microgrids to pursue various goals—from improving resilience and reliability, to improving the cost or environmental characteristics of their energy supply. As such, microgrids differ from one host institution to the next. Generally, however, a typical microgrid installation includes: on-site generation, often a cogeneration (also called “combined heat and power,” or CHP) plant that supplies both electricity and heat to the host institution, and thus is likely to be more efficient than the energy delivered by the current commercial grid; a network of sensors that monitor energy use and communicate with a central controlling device; advanced building systems that manage a variety of functions, such as lighting, traditional HVAC, and sometimes storage of cooling and heating capacity, all of which are centrally controlled; batteries and renewable energy technologies; and other devices and behavioral initiatives the host undertakes to increase efficiency. A microgrid’s electrical relationship to the larger grid is controlled by interface technologies at the point of interconnection.</p>
<p>Microgrid revenues can be derived from some or all of: a) reductions in use, stemming from energy efficiency or DR initiatives; b) more efficient purchasing of electricity, including buying off-peak electricity to reduce peak demand, often by storing it with some form of storage of thermal energy—<i>i.e.,</i> pre-heating or pre-cooling building spaces, or storing hot or chilled water; c) sales of electricity to the host institution; d) balancing generation and usage with control technology, and selling excess electricity to the grid; and e) capacity charges and other revenues stemming from the benefits supplied to the larger grid.</p>
<p>Microgrids create significant benefits when deployed in areas of the grid that need additional electrical support, or where they eliminate the need for costly grid upgrades—the so-called “non-transmission alternative” or NTA <i>(see “<a href="https://www.fortnightly.com/fortnightly/2013/04/looking-beyond-transmission">Looking Beyond Transmission</a>”)</i>. Many of these benefits accrue to the grid, not the microgrid host institution, and thus aren’t typically monetized for the benefit of the microgrid owner. To capture their full potential value, microgrids should be deployed in electrically appropriate areas of the larger grid, as was done recently by Central Maine Power and is somewhat more common in Europe.</p>
<p>Key choices faced by the microgrid host institution include: how much electricity to generate on-site; whether to operate islanded from or in parallel with the larger grid, and, if islanded, how frequently to operate in islanded mode, and toward what goals; whether to sell electricity, grid support services, or capacity to the larger grid, or to simply provide generation to meet the host institution’s needs; and whether to sell power to off-site users—that is, users not part of the host institution.</p>
<p>Microgrids operate in an intricate legal and regulatory environment—and arguably they’re proliferating in spite of it. State law determines whether a microgrid can sell electricity or steam to nearby institutions, or even branches of the host institution that happen to have another electric meter, or are located on the other side of a public street. State law and the local grid operator, which often is vested with quasi-legal authority owing to its position as a regulated monopoly, determine the extent to which a microgrid operator can sell electricity and related services to the larger grid and, in some cases, whether fully islanded operations are allowed. Federal law, as embodied in the regulations governing independent system operators and regional transmission organizations, also can inhibit microgrids when they require elaborate and expensive interconnection procedures. And microgrid operators must master a host of other legal and regulatory issues to build, operate, and maximize the benefits of their systems.</p>
<p>Sophisticated microgrids of all sizes are now operational throughout the United States, deployed by different host institutions with varying energy, financial, and operational goals. The multiple types of microgrids demonstrate the adaptability and flexibility of the model.</p>
<h4>Islanding Universities</h4>
<p>One of the most celebrated microgrids is found on the campus of the University of California-San Diego. The microgrid covers 1,200 acres and serves a daytime peak population of 45,000, plus laboratories that require an uninterruptible supply of power. The UCSD microgrid self-generates about 85 percent of its power, is capable of operating in island mode, and has a control technology that regulates energy use across the campus. UCSD claims it has helped it save almost $800,000 in monthly purchases of electricity. UCSD campus also has 11 percent of its power supplied by solar PV panels. It’s among the largest, most comprehensively designed, and renewable-enabling microgrids in the world.</p>
<p>Cornell University designed its microgrid after the blackout of 2003, when it experienced significant delays in the restoration of electricity. The university decided it wanted a secure supply of power at all times, and created a fully functioning microgrid. Today Cornell operates one of the largest microgrids in the state of New York. With several CHP generators on site, Cornell’s microgrid supplies electricity and heat to more than 150 buildings on campus, and cooling to another 75 buildings. The microgrid has optional islanding capability, but usually operates in parallel with the larger grid to supply all the campus’ electricity and thermal needs. This 35-MW system also has a control technology that regulates energy use across the campus.</p>
<p>The Illinois Institute of Technology is in the process of developing a prototype microgrid system—<i>i.e., </i>several microgrids linked together in a loop to provide a completely reliable source of electric power.<b><sup><a href="http://www.fortnightly.com/fortnightly/2013/04/smaller-cheaper-and-more-resilient?page=0%2C7" title="1. See http://www.iit.edu/perfect_power/pdfs/IITPerfectPower.pdf">1</a></sup></b> The system is designed to “eliminate costly outages, minimize power disturbances, moderate an ever-growing demand, and curb greenhouse gas emissions.” It’s projected to cost $12 million and will pay for itself in five years. IIT’s confidence in the project’s economics suggests that financing a microgrid lies within the reach of many large, financially sophisticated institutions.</p>
<h4>Absolute Security for Defense</h4>
<p>The U.S. Department of Defense has embarked on a major initiative to deploy microgrids in bases across the United States. Its reasoning emphasizes the appeal of distributed energy systems for supply security. The DoD has determined that its “installations are largely dependent on a commercial power grid that is vulnerable to disruption due to aging infrastructure, weather-related events and a potential kinetic or cyber attack.” <b><sup><a href="http://www.fortnightly.com/fortnightly/2013/04/smaller-cheaper-and-more-resilient?page=0%2C7" title="2. Statement of Dr. Dorothy Robyn, Deputy Under Secretary of Defense (Installations and Environment) before The House Armed Services Committee, Subcommittee on Readiness, March 29, 2012 at 1.">2</a></sup></b> Deployment of microgrids is the preferred strategy because “[o]n-site energy is critical to making our bases more energy secure.” Microgrids will ease integration of renewable generation, especially solar PV panels, building control systems, and advanced storage and efficiency technologies. Finally, an MIT study for the DoD concluded that “the most cost-effective microgrid solutions will be those that take into account the needs of the local commercial electric grid and implement their systems so that they can earn value helping to meet those needs.”<b><sup><a href="http://www.fortnightly.com/fortnightly/2013/04/smaller-cheaper-and-more-resilient?page=0%2C7" title="3. Microgrid Study: Energy Security for DoD Installations, Lincoln Laboratory, Massachusetts Institute of Technology, June 18, 2012 at iv.">3</a></sup></b></p>
<p>The flagship DoD microgrid is the National Interagency Biodefense Campus at Fort Detrick in Maryland. On-site cogeneration plants provide electric power, steam, and chilled water to the base’s medical and research labs. Generation capacity is being expanded substantially from 7 MW to 17 MW. Owing to its large critical-mission load and the resultant necessity of a secure supply of power, the base’s microgrid supplies power with a 99.999-percent reliability factor. This extraordinary degree of energy security is costly: prevailing local electricity rates are approximately $0.08 per kWh; Fort Detrick spends over $0.21 per kWh. In this regard, the base is an outlier among DoD installations; owing to its unique mission, it ignores the DoD cost-reduction imperative.</p>
<p>A more typical microgrid installation is the Naval Support Facility Dahlgren, in Virginia, just south of Washington, D.C. This facility has created a network of controls to monitor use of electricity, natural gas, and hot water throughout its extensive campus. Its various energy systems have been linked in a cyber-secure manner. Finally, the original diesel generators, installed because of persistent grid reliability problems, are beginning to be linked together into a true microgrid, with the same control system used in the larger commercial grid. The Dahlgren microgrid operates in parallel with the utility system to reduce demand on the larger grid, and can operate in island mode during outages. While the Dahlgren microgrid doesn’t sell electricity or grid support services to the larger grid, it does offer huge DR capacity—14 MW—to the local utility. Revenue from this program pays most of the costs of the microgrid. Dahlgren’s base commander is considering whether to incorporate renewable power into the microgrid.</p>
<h4>Hospitals and CHP</h4>
<p>Hospitals are among the most important institutions in a civic emergency and are well suited to microgrids. Microgrids can serve a hospital as well as a small or large network of surrounding facilities that are affiliated—or not—with the hospital. Of course, the legal and regulatory challenges to a microgrid increase when a microgrid seeks to sell power to adjacent, unaffiliated customers, because the local utility might have the exclusive right to sell electricity to third parties. But this concern need not prevent the development of microgrids.</p>
<p>Utica College and Faxton-St. Luke’s Healthcare created a small, shared microgrid serving the energy needs of both institutions. The 3.4-MW system, operational since 2009, uses four small CHP generators to supply Utica College, the local hospital, and an affiliated nursing home. The microgrid provides more than 80 percent of the hospital’s energy needs, 75 percent of the college’s power, and 50 percent of the nursing home’s energy needs. The microgrid can operate islanded, if the grid loses power, but typically operates parallel to the grid, and when circumstance permit, it sells excess power back to the grid.</p>
<p>In another example, a large cogeneration facility, the Medical Area Total Energy Plant (MATEP), serves major hospitals affiliated with Harvard University, as well as of other facilities in the Longwood area of Boston. This district energy system serves the energy needs of several host institutions and surrounding buildings. MATEP provides steam, chilled water, and electricity to more than 9 million square feet of space in facilities in Longwood, and seeks to provide a highly reliable source of power at affordable prices to its customers. MATEP serves five major hospitals that have over 2,000 beds, as well as biomedical and pharmaceutical research centers. A little over two years ago, the entity that owns and operates MATEP was acquired by a joint venture between Morgan Stanley Infrastructure Partners and Veolia Energy North America.</p>
<h4>Rebuilding New York’s Grid</h4>
<p>The devastation caused by Superstorm Sandy revealed the need for a new approach to delivering utility services in New York. Mayor Michael Bloomberg, in a speech on Dec. 6, 2012, pledged to “modernize our energy infrastructure by incentivizing large buildings and hospitals to invest in co-generation systems… We will work with Governor Cuomo to explore how we can accelerate investments in distributed energy, microgrids, energy storage, and smart grid technologies.”<b><sup><a href="http://www.fortnightly.com/fortnightly/2013/04/smaller-cheaper-and-more-resilient?page=0%2C7" title="4. See New York City Government press release, PR 459-12.">4</a></sup></b></p>
<p>Prospective deployment of microgrids in Long Island and New York City will have two principal goals: making the electric grid more resilient and, in case power is lost, making certain that key institutions and components of critical infrastructure retain their power and can respond to emergencies. Cooperation of the local utilities and large host institutions is vital to achieve these goals.</p>
<p>On Long Island, deployment will depend on critical choices by LIPA, National Grid, and potential host institutions. The electrical characteristics of Long Island’s grid enable full deployment of microgrids, including the sale of energy, capacity, and other grid-support services back to the bulk power grid itself. LIPA and National Grid should designate locations where they expect to recommend line upgrades requiring substantial capital costs. They also should identify locations where, for technical reasons, microgrids’ substantial reductions in load and other efficiencies would benefit the grid. These locations are prime targets for microgrids. Potential host institutions should evaluate whether a microgrid is appropriate.</p>
<p>Host institutions that might be well suited for a microgrid include: the Brookhaven National Laboratory; Hofstra University; the SUNY Stony Brook Campus; Nassau Community College; North Shore LIJ Medical Center; the Stony Brook Medical Center; South Nassau Community Hospital; Good Samaritan Community Hospital; Winthrop Community Hospital; and Hauppauge Industrial Park, as well as other institutions of similar size.</p>
<p>The best locations are those where the larger grid can benefit from a microgrid and where a significant local institution is committed to serving as a host. Also, deployment of microgrids can expand on the distributed energy assets that already exist. For example, the 45 MW of generation at SUNY Stony Brook can be upgraded to more effectively serve the campus, the surrounding area, and become a model for the deployment of microgrids across the SUNY system.</p>
<p>There also might be a federal role. Given Sandy’s effect on Long Island, the U.S. Department of Energy and the Department of Homeland Security might be able to provide technical support, funding, or both to speed the local deployment of microgrids. The DOE’s Brookhaven National Laboratory could serve an ideal location for a DOE flagship microgrid.</p>
<p>Likewise, in New York City, deployment will depend on critical choices by Con Ed and potential host institutions. However, the electrical characteristics of Con Ed’s underground distribution system can make the sale of electricity and support services back to the grid technically more challenging than usual. The enthusiastic cooperation of Con Ed will be vital to ensure that microgrids can be deployed to the fullest extent possible. Even if that weren’t to occur, very large microgrids of 25 MW and higher likely could be deployed without undue technical limitations, and smaller microgrids could deploy with all but commodity and grid support, so-called “ancillary service” sales. Potential hosts include:</p>
<ul>
<li>Private universities, like NYU<b><sup><a href="http://www.fortnightly.com/fortnightly/2013/04/smaller-cheaper-and-more-resilient?page=0%2C7" title="5. NYU reportedly operated its cogeneration system in island mode during Superstorm Sandy, and maintained service to the university’s main campus at Washington Square and some other large buildings.">5</a></sup></b> and Columbia, each of which already has substantial on-site generation assets that could transition to a full microgrid, as well as others, including Fordham, St. John’s, Yeshiva, and Pace; </li>
<li>Hospitals, whether affiliated with universities, operated as a group like Continuum, or part of the NYC Health and Hospitals Corp. A joint microgrid including Bellevue Hospital, NYU Langone Medical Center, and the large NYC men’s shelter that lies directly between them, could be ideal;</li>
<li>Housing complexes, from large NYCHA developments to private stand-alone complexes, like Stuyvesant Town, Peter Cooper Village, or Battery Park City;</li>
<li>Public universities, such as many of the CUNY campuses;</li>
<li>Economic centers like the New York Stock Exchange, data and communication centers, Rockefeller Center, the Brooklyn Navy Yard, and Hunts Point Distribution Center; and </li>
<li>Sites with critical infrastructure, such as water and sewage treatment plants, shelters and schools, and police and fire command centers.</li>
</ul>
<p>Whether any microgrid projects will emerge from the Bloomberg Administration’s current review remains uncertain. Also, since Bloomberg is now in his final term as mayor, the danger exists that current initiatives won’t survive into the next administration. It will be important to examine the findings of New York City’s infrastructure effort and incorporate the significant recommendations into any long-term plan developed by Gov. Cuomo’s administration. Additionally, the services of the New York Power Authority and NYSERDA will be important in evaluating which microgrids, if any, should receive public support.</p>
<h4>Technology’s Unstoppable Force</h4>
<p>Three barriers have prevented the wider deployment of microgrids.</p>
<p>First, potential customers face significant barriers to entry—including difficulties in learning about the microgrid product. Baldly stated, information about microgrids’ costs and benefits remains hard to obtain and difficult to understand. The host institution typically isn’t in the electricity business, and so it requires an unusual degree of leadership for a major health care, educational, or housing provider to understand microgrids’ benefits and then to make the decisions necessary to secure them. It’s no accident that many microgrids are deployed by universities with significant internal expertise in engineering and the hard sciences.</p>
<p>Second, pricing isn’t transparent. Reliability doesn’t have a price under the current grid’s regulatory regime. It’s accordingly difficult to price increased reliability. Moreover, improved reliability has broad social benefits—such as a hospital that functions during an emergency—which the host institution can’t identify or monetize.</p>
<p>Third, regulations constrain microgrids’ full development. Even if customers can learn about microgrids and decide that the benefits of a microgrid exceed its costs, the optimal deployment of a microgrid requires both an understanding of bulk power pricing—a notoriously non-transparent market—and an ability to work with local utilities and with the ISO or RTO, many of whom might view microgrids as reducing sales of electricity or damaging to wholesale market design. In such conditions, microgrids are difficult to deploy to their greatest advantage, undercutting their appeal.</p>
<p>Given the somewhat dysfunctional electricity markets, government’s role is clear. Removing informational barriers and pricing public goods are part of government’s mission. Government also should enact legislation and promulgate regulations to incentivize regulated monopolies to act in the public interest. Specifically, if microgrid expansion enhances electric security and thereby economic security, that expansion should be encouraged, and not discouraged as is likely under existing regulatory regimes.</p>
<p>A phased approach might prove to be the most successful, with government first leading the installation of microgrids in public colleges and universities as well as hospitals and other components of critical infrastructure. As these changes take root, they will create a path for more long-term legislative and regulatory reforms. It will be essential to develop partnerships with utilities from the beginning.</p>
<p>Finally, microgrids face challenges because they’re unique components of electricity infrastructure. They don’t fit within the governing central station model of power generation: electricity generated by large plants, sent long distances over transmission lines, and finally fed through distribution lines to passive end users. As such they don’t fit easily within the traditional utility operating model, and nor do they fit within the regulatory construct that has grown up around this model.</p>
<p>The conventional view is well-known within the industry. Incumbent utilities might find microgrids somewhat antagonistic to their business model. Microgrids provide generation capacity, but not within the central station model; microgrid assets might be owned by important institutions that are neither utilities nor connected to the industry; and microgrids arise from a free-market economic interest and technological capability to drive down energy use and increase the efficiency and resilience of energy services.</p>
<p>But this conventional view is dated. Technology here—as elsewhere—intrudes with unstoppable force.</p>
<p>Utilities that accept and embrace microgrids as part of 21st-century energy infrastructure will have a major role in their deployment, for several reasons. First, deployment of microgrids is technically complex. Utilities should be involved in siting them—as they are in siting new generation via the procedures of the ISO-RTOs—to ensure they benefit the larger grid. Second, utilities should help set standards for their design and site-specific configuration so islanding happens quickly and smoothly, and backup generators don’t fail as they did at the NYU Langone and Bellevue hospitals during Superstorm Sandy, forcing patients to be evacuated. Third, utilities could share in the financing of microgrids with host institutions, provided that the public benefits of the particular microgrid deployment are clear and quantifiable.</p>
<p>However, a few caveats are in order. First, utilities aren’t likely to be allowed to monopolize the microgrid business. Much like federal law prevents common control of transmission and generation assets within an organized wholesale power market to ensure healthy competition, many state laws will prohibit monopoly utility ownership of microgrids. Second, while the view that microgrids threaten utility sales is accurate, other factors—such as the deployment of power-hungry data centers—will help maintain underlying levels of electric demand, especially in urban areas.</p>
<p>One of the benefits of microgrids is their extraordinary ability to create efficiencies in and reduce the costs of electricity usage. By allowing utilities to invest in microgrids—without giving them a monopoly—regulators can create a new regime that fairly compensates utilities and their investors for participating in this new world.</p>
<h4>Endnotes:</h4>
<p>1. <i>See</i> <a href="http://www.iit.edu/perfect_power/pdfs/IITPerfectPower.pdf" target="_blank">http://www.iit.edu/perfect_power/pdfs/IITPerfectPower.pdf</a>.</p>
<p>2. Statement of Dr. Dorothy Robyn, Deputy Under Secretary of Defense (Installations and Environment) before The House Armed Services Committee, Subcommittee on Readiness, March 29, 2012 at 1.</p>
<p>3. <i>Microgrid Study: Energy Security for DoD Installations</i>, Lincoln Laboratory, Massachusetts Institute of Technology, June 18, 2012 at iv.</p>
<p>4. See <a href="http://www.nyc.gov/html/om/html/2012b/pr459-12.html" target="_blank">New York City Government press release</a>, PR 459-12.</p>
<p>5. <a href="http://green.blogs.nytimes.com/2012/11/05/how-n-y-u-stayed-partly-warm-and-lighted/?ref=energy-environment" target="_blank">NYU reportedly operated its cogeneration system in island mode during Superstorm Sandy</a>, and maintained service to the university’s main campus at Washington Square and some other large buildings.</p>
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<a href="/tags/microgrid">Microgrid</a><span class="pur_comma">, </span><a href="/tags/microgrids">Microgrids</a><span class="pur_comma">, </span><a href="/tags/distributed-generation">Distributed generation</a><span class="pur_comma">, </span><a href="/tags/dg">DG</a><span class="pur_comma">, </span><a href="/tags/distributed-energy-resources">Distributed energy resources</a><span class="pur_comma">, </span><a href="/tags/der">DER</a><span class="pur_comma">, </span><a href="/tags/hurricane-sandy">Hurricane Sandy</a><span class="pur_comma">, </span><a href="/tags/infrastructure">Infrastructure</a><span class="pur_comma">, </span><a href="/tags/emergency-services">emergency services</a><span class="pur_comma">, </span><a href="/tags/transmission-and-distribution">Transmission and distribution</a><span class="pur_comma">, </span><a href="/tags/underinvestment">underinvestment</a><span class="pur_comma">, </span><a href="/tags/cellular">cellular</a><span class="pur_comma">, </span><a href="/tags/microprocessor">microprocessor</a><span class="pur_comma">, </span><a href="/tags/internet">Internet</a><span class="pur_comma">, </span><a href="/tags/demand-response">Demand response</a><span class="pur_comma">, </span><a href="/tags/dr">DR</a><span class="pur_comma">, </span><a href="/tags/uninterrupted">uninterrupted</a><span class="pur_comma">, </span><a href="/tags/blackout">blackout</a><span class="pur_comma">, </span><a href="/tags/outage">outage</a><span class="pur_comma">, </span><a href="/tags/renewable">Renewable</a><span class="pur_comma">, </span><a href="/tags/hospital">hospital</a><span class="pur_comma">, </span><a href="/tags/water">water</a><span class="pur_comma">, </span><a href="/tags/sewer">sewer</a><span class="pur_comma">, </span><a href="/tags/universities">universities</a><span class="pur_comma">, </span><a href="/tags/restoration">restoration</a><span class="pur_comma">, </span><a href="/tags/efficiency">efficiency</a><span class="pur_comma">, 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href="/tags/central-maine">Central Maine</a><span class="pur_comma">, </span><a href="/tags/island">island</a><span class="pur_comma">, </span><a href="/tags/parallel">parallel</a><span class="pur_comma">, </span><a href="/tags/independent-system-operators">Independent system operators</a><span class="pur_comma">, </span><a href="/tags/regional-transmission-organization">regional transmission organization</a><span class="pur_comma">, </span><a href="/tags/university-california-san-diego">University of California-San Diego</a><span class="pur_comma">, </span><a href="/tags/ucsd">UCSD</a><span class="pur_comma">, </span><a href="/tags/cornell">Cornell</a><span class="pur_comma">, </span><a href="/tags/illinois-institute-technology">Illinois Institute of Technology</a><span class="pur_comma">, </span><a href="/tags/department-defense">Department of Defense</a><span class="pur_comma">, </span><a href="/tags/dod">DOD</a><span class="pur_comma">, </span><a href="/tags/mit">MIT</a><span 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</span><a href="/tags/andrew-cuomo">Andrew Cuomo</a><span class="pur_comma">, </span><a href="/tags/lipa">LIPA</a><span class="pur_comma">, </span><a href="/tags/national-grid">National Grid</a><span class="pur_comma">, </span><a href="/tags/brookhaven">Brookhaven</a><span class="pur_comma">, </span><a href="/tags/hofstra">Hofstra</a><span class="pur_comma">, </span><a href="/tags/syny">SYNY</a><span class="pur_comma">, </span><a href="/tags/nassau">Nassau</a><span class="pur_comma">, </span><a href="/tags/north-shore">North Shore</a><span class="pur_comma">, </span><a href="/tags/stony-brook">Stony Brook</a><span class="pur_comma">, </span><a href="/tags/south-nassau">South Nassau</a><span class="pur_comma">, </span><a href="/tags/good-samaritan">Good Samaritan</a><span class="pur_comma">, </span><a href="/tags/winthrop">Winthrop</a><span class="pur_comma">, </span><a href="/tags/hauppauge">Hauppauge</a><span class="pur_comma">, </span><a href="/tags/long-island">Long Island</a><span class="pur_comma">, </span><a href="/tags/department-homeland-security">Department of Homeland Security</a><span class="pur_comma">, </span><a href="/tags/con-ed">Con Ed</a><span class="pur_comma">, </span><a href="/tags/nyu">NYU</a><span class="pur_comma">, </span><a href="/tags/columbia">Columbia</a><span class="pur_comma">, </span><a href="/tags/bellevue">Bellevue</a><span class="pur_comma">, </span><a href="/tags/langone">Langone</a><span class="pur_comma">, </span><a href="/tags/nycha">NYCHA</a><span class="pur_comma">, </span><a href="/tags/cuny">CUNY</a><span class="pur_comma">, </span><a href="/tags/rockefeller">Rockefeller</a><span class="pur_comma">, </span><a href="/tags/brooklyn">Brooklyn</a><span class="pur_comma">, </span><a href="/tags/hunts-point">Hunts Point</a><span class="pur_comma">, </span><a href="/tags/bulk-power">bulk power</a><span class="pur_comma">, </span><a href="/tags/government">government</a><span class="pur_comma">, </span><a href="/tags/central-station">central station</a> </div>
</div>
Mon, 08 Apr 2013 10:12:38 +0000meacott16529 at http://www.fortnightly.comBill Hogan, Unbundledhttp://www.fortnightly.com/fortnightly/2012/11/bill-hogan-unbundled
<div class="field field-name-field-import-deck field-type-text-long field-label-inline clearfix"><div class="field-label">Deck:&nbsp;</div><div class="field-items"><div class="field-item even"><p>A candid commentary on current topics in electric restructuring.</p>
</div></div></div><div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>John A. Bewick</p>
</div></div></div><div class="field field-name-field-import-category field-type-text field-label-inline clearfix"><div class="field-label">Category:&nbsp;</div><div class="field-items"><div class="field-item even">People In Power</div></div></div><div class="field field-name-field-import-bio field-type-text-long field-label-inline clearfix"><div class="field-label">Author Bio:&nbsp;</div><div class="field-items"><div class="field-item even"><p><b>John A. Bewick</b> is <i>Fortnightly’s</i> contributing editor and formerly was secretary for environmental affairs for the Commonwealth of Massachusetts. He holds advanced degrees in nuclear science and business management.</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - November 2012</div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p>Energy planners and utility owners are hearing rumblings about tsunamis of change in the electricity market, triggered by earthquakes of uncertainty. Where does the uncertainty arise? The growth of renewables, the emergence of regional electricity markets, innovations in energy technology, changes in distribution systems with smart metering, demand management, and global economic upheavals all contribute to this tectonic shifting.</p>
<p>The lack of a clear national energy policy hasn’t helped to add clarity, as <i>Fortnightly</i> Editor-in-Chief Michael Burr pointed out in a recent “Frontlines” column <i>(see “<a href="http://www.fortnightly.com/fortnightly/2012/09/mitt-romney-and-you">Mitt Romney and You</a>,” September 2012)</i>. The Federal Energy Regulatory Commission (FERC) has contributed to uncertainty with controversial regulations that some view as confiscatory. While investors try to preserve and protect traditional energy sources and maintain profitability, they oppose plans for investment in new renewable innovations.</p>
<p>Since technology developments will dictate the future, resistance to change isn’t productive. Yet, keeping electricity on all the time is much more complex with a stream of less-reliable renewables.</p>
<p>In the ever-changing world of energy markets there are still several constants. One is the consistently reliable counsel of William W. Hogan, the chief architect of wholesale electric market design in the United States. His thoughts and models have shaped energy policy for decades. Currently the Raymond Plank Professor of Energy Policy at the John F. Kennedy School of Government, Hogan recently spoke with <i>Fortnightly</i> about electric market reform and its effect on electric industry restructuring. He discussed the successes and challenges of deregulation, market models, and the problems encountered on the path toward organized wholesale power markets.</p>
<p>Of course, this path hasn’t been altogether smooth. Along the way, a number of different industry sectors and institutional actors have questioned whether Hogan’s ideas on electric market reform have aided overall industry efficiency or produced notable consumer benefits. The American Public Power Association, for example, has for some time now maintained a section on its website <i>(<a href="http://www.publicpower.org">www.publicpower.org</a>)</i> that offers analytical studies by industry or academic economists that seek to answer the question of whether ratepayers are better off now—what with electric restructuring, regional grid operators, and centralized wholesale power markets—than they would have been under a parallel, but different universe.</p>
<p>Anyone with more than a passing interest in these subjects should take a look at the APPA site, starting with the APPA’s own <i>Electric Market Reform Initiative</i> (EMRI), and APPA’s web link to various investigative studies of the nation’s restructured RTO-operated wholesale electricity markets. The student also should note the APPA’s own proprietary study: <i>APPA’s Competitive Market Plan: A Roadmap for Reforming Wholesale Electricity Markets</i> (2011 Update). <i> </i></p>
<p>In that context, Hogan started by addressing some of the ideas he presented in his article, “Electricity Market Reform: APPA’s Journey Down the Wrong Path,” co-authored with John Chandley in 2009. <i> </i></p>
<p><strong><span class="boldred">Fortnightly: </span></strong>What are the two or three biggest successes of deregulation, after a decade of experience, and the two or three biggest challenges still facing deregulation?</p>
<p><b>William Hogan:</b> This is addressed in the article I wrote with John Chandley in 2009. There are three arguments in there: What’s wrong with what the APPA is suggesting? Do you want to have open access and competitive markets or not? And do you want to have regulation or deregulation?</p>
<p>As an example of the success of deregulation, look at what happened to nuclear power. You have nuclear power plants, where the average capacity factor was in the low 60s. Now it’s in the 90s. That was driven by the competitive pressures of privatization in some sense—the investors had to make a profit from it. The nuclear plants weren’t living off the cost-plus world that was driving the cost up and performance down. That’s been a terrific example of the benefit of deregulation.</p>
<p><strong><span class="boldred">Fortnightly: </span></strong>That’s a good example. It’s the equivalent of a 50 percent increase in capacity, without building a single plant. What about other examples of investments in an era of deregulation?</p>
<p><b>Hogan:</b> You have to take a look at some anecdotal information, like the famous graphic when AEP joined PJM, and what happened to their inter-regional trading. <em>(See page 34 of “Electricity Market Reform,” 2009)</em>.</p>
<p>You have to think about this. Here’s AEP, one of the most sophisticated utilities in the country, extremely confident about its ability to trade in markets and capture all the economic benefits. They didn’t think the regional transmission organizations [RTO] were important. And then they joined PJM. Their trading in exports [from] Midwest to East went up dramatically when they joined PJM and got access to efficient dispatch.</p>
<p>The picture is stunning when you look at it. You don’t have to be an econometrician to figure this one out.</p>
<p><span class="boldred"><strong><span class="boldred">Fortnightly:</span></strong></span> What are the implications of deregulation on investment practices and behavior? Who wins and who loses?</p>
<p><b>Hogan:</b> There are examples of things that aren’t very pleasant, but which are also part of the design. When we had the dash to gas, and were building all these [gas-fired] plants. Investors overestimated how much they were going to make, and that led to a big round of bankruptcies among new independent power producers. Well, in the old days, this would’ve been a stranded-asset problem, and the utility would’ve gotten recovery of the cost for all the things it had built. All of this would have been passed onto the consumer, and there would have been a great amount of regulatory proceedings. They would’ve said the utility “wasn’t prudent” and “should have known”—all this kind of stuff. None of that happened, right? They just went bankrupt. And their shareholders hated it. And that was the idea!</p>
<p>Most importantly—and this is the dog that didn’t bark—they stopped investing in that stuff—unlike [regulated utilities at] Shoreham. Think about the Shoreham (New York) nuclear power plant, where at about every $1 billion [of investment] they stopped and did an assessment. After they got to $6 billion, the governor intervened, the work was stopped. And all the ultimate generation was zero megawatt hours. So $6 billion divided by zero megawatt hours is the price to beat.</p>
<p><strong><span class="boldred">Fortnightly:</span></strong> When and how can you direct your investments to ensure long-term benefits?</p>
<p><b>Hogan:</b> The truth of the matter is that the real benefits are going to be measured in long-term investment profiles. Even now it’s a little early to tell how this is going to unfold. We have all the complications of the renewable subsidies and things like that obfuscating what’s going on here. Think about, for example, the green agenda. If you want innovation, you have to get the incentives and the structure right. Vertically integrated monopolies are not the way to get that done.</p>
<p>I think there’s a case to be made that the benefits of renewables are positive and that they’re growing.</p>
<p><strong><span class="boldred">Fortnightly:</span></strong> In California, we saw a complete failure in the management of energy markets. Why the collapse? And how do you organize the market correctly?</p>
<p><b>Hogan:</b> Now my explanation about California is that this was caused by bad regulations, not deregulation, and the principal problems were due to the interventions by the governor and by the Federal Energy Regulatory Commission. The governor lost his job, appropriately. It wasn’t caused by markets, but, nonetheless, that was a real catastrophe. So [what caused the crisis] is an interesting question. But whether or not you want to have open competition is another.</p>
<p>There’s a third question, though, which APPA proposed <em>(see “Energy Market,” 2009)</em>, and that is, “Do you want to have regulation or deregulation?” I think this is a misleading way of asking whether you want to “restructure” deregulation. There’s a lot of regulation [in competitive markets]. The question that people get confused about all the time, and which is extremely important, is: “If you want a competitive open access market without discrimination, what is the appropriate organization of that market? What is the appropriate market design?”</p>
<p>It’s extremely important that you get that right, and it’s evident there’s only one way to do it. If you look at the cost-benefit analysis, comparing doing it the wrong way, like California, versus doing it the right way, like the current version of PJM, for example, then you find enormous differences in approach to the appropriate market design. And so the market design question is a much easier question to answer. It’s clear that it’s important. It’s clear that if you don’t get it right you can cause a lot of trouble. And it’s also clear what the answer is.</p>
<p><strong><span class="boldred">Fortnightly:</span></strong> So, what is the answer? What is the appropriate market design for the electrical energy market?</p>
<p><b>Hogan:</b> We’re now in a situation where the core feature of the market design is a “mid-base, security constrained, economic dispatch with locational prices.” This I gave as a name to the model.</p>
<p>That model emerged after some experimentation—trying other ways that were supposedly simpler or easier. It turns out there aren’t any other ways that actually work. There are a lot of ways that look simpler on paper, but they don’t actually work because they’re inconsistent with reality.</p>
<p>Every organized market in the United States now uses that model. New England started out with a different approach, and they now use it. New York has always used it. PJM started out a different way and they now use it. SPP [Southwest Power Pool] tried something else, that didn’t work, and it’s now using it. California tried something else and it didn’t work, and they’re using it. Texas tried something different, and it didn’t work and they’re now using it. So that’s a pretty strong empirical record.</p>
<p>The core principle is that you’re accepting the bids and the offers that people make from different generators. You’re doing security constraints, so that reliability constraints are imposed. You do economic dispatch. So, subject to those constraints, you find the least-bid cost based on the bids of the lowest-cost point of operating the system. And then you price locationally at the nodes, which is where the difference in demand is.</p>
<p>You don’t try to aggregate those nodes when figuring out what these prices are. You aggregate them for billing purposes later on. When you’re actually doing the model, and you’re charging generators and paying everybody and you charge for transmission between locations, well, that’s the difference in price. That’s the basic core model, and everybody does that.</p>
<p><strong><span class="boldred">Fortnightly:</span></strong> Are there variations on the core model that RTOs use?</p>
<p><b>Hogan:</b> Now they do different things, and there can be variations in certain circumstances:</p>
<ul>
<li>When they’re dealing with financial transmission rights;</li>
<li>When they’re aggregating prices for customers, the average, and so forth;</li>
<li>When they have different ways of dealing with the capacity markets, which I didn’t mention because they’re not part of the design;</li>
<li>When they do different things for transmission rights, and;</li>
<li>When they do different things for transmission cost allocation.</li>
</ul>
<p>Those are all important issues, and some are good and some are bad. But the core—which is a big idea and extremely important—is that there’s basically only one way to do it.</p>
<p><strong><span class="boldred">Fortnightly:</span></strong> That sounds simple, but everyone knows it isn’t. What do you see as the details that need attention?</p>
<p><b>Hogan:</b> The model I just described exists in all the organized markets. It doesn’t exist outside the organized markets, the ISOs and RTOs. If open access and non-discrimination is supposedly our [national] policy, then every place that hasn’t adopted this isn’t achieving open access and non-discrimination.</p>
<p>So extending the model of the ISO or RTO to the rest of the country should be a high priority for FERC. They’re long overdue in dealing with this application. They’ve had opportunities to do it, but there are political reasons they don’t want to pick up that rock. And I understand those political reasons. They’re very powerful, and there’s a lot of pressure. But in the end you can’t have it both ways. If you say “We have open access and non-discrimination as our policy in the country and we have a market design that’s necessary if we’re going to do that,” you can’t also say “If we don’t have the market design in the country, then everything is OK.” Both can’t be true.</p>
<p>It’s not actually hard to implement technically. It may be that the political problems are overwhelming, but then [FERC] should stand up and say: “We can’t implement open access here because of these political obstacles.” But don’t pretend that you’re doing otherwise. There’s a lot of mumbling these days.</p>
<p><b>Editor’s Note: </b><i>While FERC has chosen not to mandate RTO formation across the country, it has long promised to develop industry performance metrics for non-RTO areas, to complement the performance metrics its staff adopted for RTOs in 2010. And on October 15, as this issue was going to press, the FERC staff in fact released a report describing a final set of 39 non-RTO performance metrics (Docket AD12-8-000, “Performance Metrics in Regions Outside ISOs and RTOs”). A possible next step, the report states, will be to “establish common metrics between ISOs/RTOs and non-ISO/RTO regions.” The implication is clear: at some future date FERC may use these common metrics to draw direct comparisons between RTOs and non-RTO regions—on operational efficiency, as well as price.–Ed. </i></p>
<p><strong><span class="boldred">Fortnightly:</span></strong> Has FERC moved in any way to adopt the core model, in spite of political obstacles?</p>
<p><b>Hogan:</b> FERC had an opportunity several years ago, when they were reviewing their transmission open access policies. John Chandley and I wrote what I thought was a brilliant paper at the time, and submitted it <i>pro bono</i>.</p>
<p>If you want to say you have open access and non-discrimination, one of the most critical services for transmission is balancing. You want to have efficient balancing. And if you have efficient balancing, then that means economic dispatch of the balancing market over several groups. And then you want to price that in a way that’s consistent with economic balancing in locational prices. So you could have a balancing market with economic dispatch, bids, security constraints, and locational prices. Just require that. Don’t say anything else. You have to do that. Then everything else follows.</p>
<p>And that actually is what SPP is [doing]. So it works just fine. FERC hasn’t done this, but they could do that anywhere if they had any spine.</p>
<p><span class="boldred"><strong><span class="boldred">Fortnightly:</span></strong> </span>Where should FERC be focusing its efforts, or what initiative should they follow to help the markets, if political considerations prevent them from imposing market design?</p>
<p><b>Hogan:</b> There’s a series of possible initiatives with various degrees of urgency. One of them falls under the general heading of market manipulation. There are a lot of enforcement actions that have been starting to come out of the enforcement office of FERC with interpretations of the rules that are new, and quite threatening to markets. This is a very serious problem. Here’s a situation where basically nobody knows what the rules are. FERC enforcers are making them up as they go along.</p>
<p>I don’t think the Commission knows this, and I don’t think they’re getting told the straight story. I think the people in the enforcement office don’t know what they’re doing, and, in many ways, don’t care. So, for example, I believe they think that if they had a strong enforcement case, even though it would completely cripple the operation of competitive markets, that would be OK. They don’t think that’s in their remit. It’s not their problem.</p>
<p>It’s a serious situation. With a court proceeding, all information could become public, you could begin making these arguments, and you could expose the nonsense that’s going on. And then maybe we’ll get some reaction from the courts and FERC. But this is actually a time bomb that’s out there, and I would worry about that.</p>
<p><strong><span class="boldred">Fortnightly:</span></strong> What are some of the other problems you see FERC reluctant to address?</p>
<p><b>Hogan:</b> The second issue, which is very public, and which you can read about in the August 2012 issue of <i>Public Utilities Fortnightly</i>, addresses the payload and demand response story. There’s a great piece by Bruce Radford <i>(“<a href="https://www.fortnightly.com/fortnightly/2012/08/making-demand-more-dynamic">Making Demand More Dynamic</a>”) </i>that<i> </i>summarizes the debate. I agree with what he said, at the same time that I don’t agree with what Audrey Zibelman said in the same issue <i>(“<a href="http://www.fortnightly.com/fortnightly/2012/08/load-resource">Load as a Resource</a>”)</i>. But this is a continuing problem. It’s a mess. And it’s also beginning to become entangled in the enforcement actions. People who are following the incentives of the demand response program are being brought up for enforcement actions because they’re doing things that are uneconomic. And you say “No kidding!”</p>
<p>Another problem is scarcity pricing. We’ve had this festering problem for years and years. The prices in the energy market are too low, even though people are always complaining about prices being too high. You can go through the analysis, and see that they’re too low. This is the “missing money” problem, as it’s called.</p>
<p>There’s a list of 25 things that system operators do that cause prices to get depressed. Paul Joskow wrote a nice paper about this a few years ago. <i>[See “<a href="http://economics.mit.edu/files/2095" target="_blank">Capacity Payments in Imperfect Electricity Markets: Need and Design</a>,” MIT Department of Economics, Dec. 5, 2007.]</i> The shortlist includes things like price caps. They bring out emergency reserves, which are real expensive, versus the price; they do demand response which is real expensive, and that depresses the price. So there are all sorts of reasons the prices are too low and the system is tight. They’re trying to fix it. Scarcity pricing has been, I think, a critical item for a long time, and I’ve been teaching about it. I keep going down to make speeches at FERC. They keep saying “You’re right in theory.” But in practice, this isn’t high on their list, and they say they’ll do it later. But I want to tell them “Now is later.”</p>
<p><strong><span class="boldred">Fortnightly:</span></strong> What’s your view of FERC’s approach to transmission cost allocation?</p>
<p><b>Hogan:</b> FERC wants to build more transmission, particularly to get [access to] renewables. They want to socialize the cost, which would make their life easier. They end up with situations with people who aren’t benefiting or maybe even losing because of the transmission, and have to pay for it. They take them to court, and [the courts] say, “You know you can’t do this. You can’t charge people if they get no benefit.”</p>
<p>So you have to do the cost allocation so that it’s roughly commensurate with the benefits. The courts said “We’re not assigning precision, but you have to have something like this.” And then FERC comes back and says “Of course, that’s what we meant.” And then they issued a notice of proposed rulemaking [NOPR], which took a year. And during that time they kept approving cost socialization.</p>
<p>At the end of the NOPR, they issued an order that said, “When a beneficiary pays, that’s what we meant.” And now we’re going to ask all of the ISOs to figure out over the next 18 months the rules for how to do this, with absolutely no guidance as to how to do it. When they asked me what I thought when the order was passed, I said, “Well, they didn’t say anything bad.” And then I predicted what was going to happen for the first year of this stakeholder process. They’re going to thrash around, they’re going to try to come up with a rule of thumb and some simple-minded way of doing it that would end up being cost socialization again.</p>
<p>And that’s what FERC wants. They want to claim the rulemaking is one thing, but have it be the other. And then they’re going to wake up as they get toward the end, which is about now, and realize that the rules they’re proposing don’t make any sense, are not logical, are not connected to the benefits, and are not going to stand up in court. And then they’re going to have to adopt something completely different.</p>
<p>I’ve been going around and making speeches about a completely different way to do it that I consider to be completely obvious. Of course they don’t like it because it requires you to actually be clear about what you’re doing. But that problem isn’t going away.</p>
<p>There’s a related problem, uplift allocation, which is a big to-do at the moment. Basically, the question is, how should you treat virtual transactions in the day-ahead market. Should you treat uplift as [allocable to] virtual transactions as opposed to allocating uplift at an actual load? I’m a strong believer that you should allocate it to the actual load. All the arguments about allocating to the virtual transaction are answering the wrong questions. But that’s a more complicated issue.</p>
</div></div></div><div class="field field-name-field-article-category field-type-taxonomy-term-reference field-label-above clearfix"><h3 class="field-label">Category (Actual): </h3><ul class="links"><li class="taxonomy-term-reference-0"><a href="/article-categories/ferc">FERC</a></li><li class="taxonomy-term-reference-1"><a href="/article-categories/etrm-markets">ETRM &amp; Markets</a></li><li class="taxonomy-term-reference-2"><a href="/article-categories/transmission">Transmission</a></li></ul></div><div class="field field-name-field-members-only field-type-list-boolean field-label-above"><div class="field-label">Viewable to All?:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-article-featured field-type-list-boolean field-label-above"><div class="field-label">Is Featured?:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-department field-type-taxonomy-term-reference field-label-above clearfix"><h3 class="field-label">Department: </h3><ul class="links"><li class="taxonomy-term-reference-0"><a href="/department/people-power">People In Power</a></li></ul></div><div class="field field-name-field-image-picture field-type-image field-label-above"><div class="field-label">Image Picture:&nbsp;</div><div class="field-items"><div class="field-item even"><img src="http://www.fortnightly.com/sites/default/files/1211-pip.jpg" width="1500" height="1081" alt="" /></div></div></div><div class="field field-name-field-fortnightly-40 field-type-list-boolean field-label-above"><div class="field-label">Is Fortnightly 40?:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-law-lawyers field-type-list-boolean field-label-above"><div class="field-label">Is Law &amp; Lawyers:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-tags field-type-taxonomy-term-reference field-label-above clearfix">
<div class="field-label">Tags:&nbsp;</div>
<div class="field-items">
<a href="/tags/restructuring">Restructuring</a><span class="pur_comma">, </span><a href="/tags/renewable">Renewable</a><span class="pur_comma">, </span><a href="/tags/regional-electricity-markets">regional electricity markets</a><span class="pur_comma">, </span><a href="/tags/smart-metering">Smart metering</a><span class="pur_comma">, </span><a href="/tags/demand-management">Demand management</a><span class="pur_comma">, </span><a href="/tags/federal-energy-regulatory-commission">Federal Energy Regulatory Commission</a><span class="pur_comma">, </span><a href="/tags/ferc">FERC</a><span class="pur_comma">, </span><a href="/tags/raymond-plank">Raymond Plank</a><span class="pur_comma">, </span><a href="/tags/american-public-power-association">American Public Power Association</a><span class="pur_comma">, </span><a href="/tags/appa">APPA</a><span class="pur_comma">, </span><a href="/tags/electric-market-reform-initiative">Electric Market Reform Initiative</a><span class="pur_comma">, </span><a href="/tags/emri">EMRI</a><span class="pur_comma">, </span><a href="/tags/chandley">Chandley</a><span class="pur_comma">, </span><a href="/tags/deregulation">Deregulation</a><span class="pur_comma">, </span><a href="/tags/nuclear">Nuclear</a><span class="pur_comma">, </span><a href="/tags/aep">AEP</a><span class="pur_comma">, </span><a href="/tags/pjm">PJM</a><span class="pur_comma">, </span><a href="/tags/rto">RTO</a><span class="pur_comma">, </span><a href="/tags/stranded-asset">stranded-asset</a><span class="pur_comma">, </span><a href="/tags/shoreham">Shoreham</a><span class="pur_comma">, </span><a href="/tags/iso">ISO</a><span class="pur_comma">, </span><a href="/tags/spp">SPP</a><span class="pur_comma">, </span><a href="/tags/radford">Radford</a><span class="pur_comma">, </span><a href="/tags/zibelman">Zibelman</a><span class="pur_comma">, </span><a href="/tags/joskow">Joskow</a><span class="pur_comma">, </span><a href="/tags/mit">MIT</a><span class="pur_comma">, </span><a href="/tags/nopr">NOPR</a><span class="pur_comma">, </span><a href="/tags/market-design">market design</a><span class="pur_comma">, </span><a href="/tags/harvard-university">Harvard University</a><span class="pur_comma">, </span><a href="/tags/william-hogan-0">William A. Hogan</a> </div>
</div>
Tue, 13 Nov 2012 17:49:39 +0000puradmin16343 at http://www.fortnightly.comEnergy Storage Solutionshttp://www.fortnightly.com/fortnightly/2012/05/energy-storage-solutions
<div class="field field-name-field-import-deck field-type-text-long field-label-inline clearfix"><div class="field-label">Deck:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Barriers and breakthroughs to a smarter grid.</p>
</div></div></div><div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Bradford P. Roberts</p>
</div></div></div><div class="field field-name-field-import-category field-type-text field-label-inline clearfix"><div class="field-label">Category:&nbsp;</div><div class="field-items"><div class="field-item even">Technology Corridor</div></div></div><div class="field field-name-field-import-bio field-type-text-long field-label-inline clearfix"><div class="field-label">Author Bio:&nbsp;</div><div class="field-items"><div class="field-item even"><p><b>Brad Roberts</b> is director, power quality products, with S&amp;C Electric Co.</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - May 2012</div></div></div><div class="field field-name-field-import-image field-type-image field-label-above"><div class="field-label">Image:&nbsp;</div><div class="field-items"><div class="field-item even"><img src="http://www.fortnightly.com/sites/default/files/1205-TCpic1.jpg" width="1500" height="944" alt="The world’s first grid-scale flywheel energy storage plant, Beacon Power’s 20-MW facility provides rapid-response frequency regulation service to the state of New York’s electric grid. (Beacon Power)" title="The world’s first grid-scale flywheel energy storage plant, Beacon Power’s 20-MW facility provides rapid-response frequency regulation service to the state of New York’s electric grid. (Beacon Power)" /></div><div class="field-item odd"><img src="http://www.fortnightly.com/sites/default/files/1205-TCpic2.jpg" width="1500" height="987" alt="A 25-kVA community energy storage unit provides one to three hours of battery power to multiple homes during outages. Utilities can aggregate many distributed, grid-tied units to improve power quality and voltage control." title="A 25-kVA community energy storage unit provides one to three hours of battery power to multiple homes during outages. Utilities can aggregate many distributed, grid-tied units to improve power quality and voltage control." /></div><div class="field-item even"><img src="http://www.fortnightly.com/sites/default/files/1205-TCpic3.jpg" width="1500" height="1254" alt="Integrated with West Virginia’s Laurel Mountain Wind Farm, AES Energy Storage runs the world’s largest lithium-ion battery plant (32 MW), which sells short bursts of power to utilities to regulate grid frequency. (AES Energy Storage)" title="Integrated with West Virginia’s Laurel Mountain Wind Farm, AES Energy Storage runs the world’s largest lithium-ion battery plant (32 MW), which sells short bursts of power to utilities to regulate grid frequency. (AES Energy Storage)" /></div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p>Energy storage holds immense potential to transform our power infrastructure into a more reliable, efficient, and economical system, with increased capacity precisely when and where it’s needed. Often called the “silver bullet” of intelligent electric grids, storage can provide unprecedented control when it comes to balancing power sources and loads, while providing green energy that reduces reliance on fossil fuels. But more progressive regulatory policies and proactive legislation are needed, including more tax credit incentives to offset significant up-front investment costs, in order to accelerate the development and deployment of clean, grid-connected energy storage.</p>
<p>The U.S. energy storage market exceeded $1 billion in 2011 and could surpass the $5 billion mark in 2014, according to a recent KEMA study. This growth is driven heavily by the renewables market, which benefits from storage technologies to integrate wind, solar, and other variable resources into the grid. In a more fertile regulatory and legislative climate, the U.S. energy storage market could swiftly grow into the tens of billions of dollars, particularly as the diverse applications and value of energy storage—beyond renewables integration—are more widely acknowledged and promoted by industry and government.</p>
<p>Until recently, legislative and regulatory milestones were few and far in between, slowing market adoption of newer energy storage technologies. Storage is complex in that it can’t always be neatly categorized as generation, transmission, or distribution—it cuts across all three sectors. Finding proper, effective ways to integrate storage into the utility rate base presents real challenges, yet it needs to happen in the very near future. The difficulty in categorizing storage has created barriers to policy and legislation, which also view generation, transmission, and distribution as separate entities. However, now that more application data is becoming available to reinforce the diverse benefits of energy storage, regulators are better armed to break down these barriers faster.</p>
<h4>Regulatory Milestones and Obstacles</h4>
<p>In October 2011, the U.S. Federal Energy Regulatory Commission (FERC) issued Order No. 755, which promotes energy storage through one of its key applications, frequency regulation, an ancillary service that helps stabilize the grid. A breakthrough for smart grid energy storage and fair business practices, FERC 755 established a new “pay for performance” compensation method for frequency regulation services provided to the grid in regional transmission organization (RTO) and independent system operator (ISO) markets, which cross state lines. It should be fully implemented by the end of 2012.</p>
<p>Previously, RTOs and ISOs had paid providers the same rate for frequency regulation services supplied by fast-ramping storage systems, such as batteries and flywheels, as they paid for services supplied by traditional fossil-fuel plants and gas-fired turbines, which are slower, less efficient, and not as environmentally friendly. FERC 755 helps level the playing field, encouraging the development and deployment of more types of storage systems, which can correct grid imbalances faster than traditional assets and cut the overall energy costs to provide these services.</p>
<p>In addition to FERC’s pivotal pay-for-performance rule for organized U.S. wholesale electricity markets, the commission is investigating development of competitive ancillary services markets outside of ISOs and RTOs. FERC’s new notice seeks input on facilitating development of markets in which providers of all storage types and capacities can fairly compete to provide grid ancillary services. It also requests comments on how storage can play a unique role in delivering multiple services, not limited to ancillary. To determine the next step in extending pay-for-performance to all storage providers, FERC continues to examine input from industry, storage advocates, and other sources, while monitoring RTO and ISO market progress on Order 755.</p>
<p>The most formidable remaining regulatory obstacles center on including storage systems as full participants in energy markets and system designs. For example, transmission providers should be allowed to own or contract with energy storage providers in order to use their services to enhance grid reliability or address congestion issues and receive cost recovery support from regulators to manage a specific problem. To date, the most notable progress on this front is in Texas, where the state’s Public Utility Commission (PUC) made a cost recovery exception for a transmission company’s large-scale battery project due to the power reliability improvement it provided. The rules need to be rewritten to allow such exceptions on a regular basis.</p>
<p>Likewise, in capacity markets, storage facilities should be allowed to compete with other peaking resources, such as natural gas-fired plants. Enacting regulations that would allow energy storage resources to compete in both the capacity and ancillary services markets would enable storage providers to recover their fixed costs in both markets in the same way fossil fuel-based generation providers do today, further leveling the playing field.</p>
<h4>Growing Government Support</h4>
<p>In the same year (2009) the U.S. Department of Energy (DOE) awarded $185 million of $778 million in smart grid funding to energy storage initiatives, the <i>Storage Technology for Renewable and Green Energy Act</i> was introduced with the hope that it would be quickly passed into law. This bipartisan legislation (S. 1845), spearheaded by Senators Ron Wyden (D-Ore.), Susan Collins (R-Maine), and Senate Energy Committee Chairman Jeff Bingaman (D-N.M.), would help accelerate development and deployment of storage technologies to support renewable generation and better manage peak loads by storing energy generated during off-peak hours and re-dispatching that energy when and where it’s needed. However, the bill stalled in committee and was introduced for the third year running in 2011.</p>
<p>The reintroduced <i>Storage Act</i><i> of 2011</i> (still S. 1845) offers a federal renewable energy investment tax credit covering all storage types, from utility-scale grid-tied assets to onsite storage that enables residences and businesses to support their own energy needs and employ small-scale renewables. Grid-tied initiatives are eligible for a tax credit of 20 percent of the total project cost, with a per-project cap of $40 million. Onsite initiatives can receive a tax credit of 30 percent of the total project cost, with a per-project cap of $1 million. By supporting all storage types, the <i>Storage Act</i> would help boost the reliability, efficiency, and capacity of the nation’s grid. Advocates are hopeful that the <i>Storage Act</i> will gain due attention in 2012 in the Senate. A companion bill, introduced in the House at the end of February 2012 (H.R. 4096), will help move the discussion forward in both bodies of Congress concurrently.</p>
<p>To help accelerate R&amp;D efforts, DOE announced its Energy Innovation Hub for Batteries and Energy Storage in 2012. This unique federal program fuels electrochemical storage discoveries that will yield more reliable, efficient, economic solutions for the nation’s grid and transportation, including plug-in electric vehicles (PEV). This year, the Hub will receive $20 million from the 2012 <i>Consolidated Appropriations Act</i>. Over five years, DOE could invest $120 million in this program, which takes an interdisciplinary approach to advancing technologies that improve grid reliability and efficiency, help integrate renewables, and support PEV adoption. The Hub unites today’s top minds in science, engineering, and industry to achieve breakthroughs in energy storage research.</p>
<p>At the state level, California, Texas, and New York are blazing trails in energy storage legislation and key initiatives, setting powerful examples for the nation. While other states are also making strides in storage, these prime movers continue to be the big three to watch.</p>
<h4>California’s Progressive Initiatives</h4>
<p>From its landmark Energy Storage Law to its recently amended Self-Generation Incentive Program (SGIP), California maintains its edge in progressive storage initiatives. The California Energy Storage Alliance (CESA), a coalition for expanding storage’s role in renewables growth and improving power systems, has been involved in nearly every legislative and policy effort promoting storage in the state.</p>
<p>Strongly influenced by CESA, California’s 2010 Energy Storage Law provides residents with cleaner, more reliable, lower cost energy while reducing the need for new transmission lines. This law increases use of large-scale energy storage, which can dispatch renewables. It also requires publicly owned and investor-owned utilities to procure grid-connected storage systems—or to employ these services—with a minimum capacity of 2.25 percent of peak load (five-year average) by 2014 to 2015, and 5 percent by 2020. Effective January 2011, the law also requires utilities to implement a five-year program for shifting air conditioning and refrigeration loads to off-peak periods to cut carbon emissions and energy costs. Leveraging this law, the California Public Utilities Commission (CPUC) also will invest a higher return rate (0.5 to 1.0 percent) into new storage systems.</p>
<p>Initially cultivated as a peak load reduction program in response to California’s 2001 energy crisis, the CPUC’s extremely popular SGIP encourages consumers and businesses to support distributed energy resources. It offers the state’s sizable credit—$2 per watt—for systems installed on the customer side of the meter, including wind turbines, fuel cells, waste heat power technologies, and others. With a $5 million per-project cap, SGIP targets residential and commercial systems versus utility-scale deployments.</p>
<p>With assistance from CESA, SGIP was amended in fall 2011 to encompass standalone energy storage systems. Previously, storage qualified for a credit when coupled with a renewable resource—customers received the $2 per-watt credit toward the installed storage system cost. Now standalone storage qualifies for the same credit. This amendment will fuel greater interest in storage by enabling customers to invest in technologies that once were financially out of reach.</p>
<h4>Big Moves in Texas</h4>
<p>Energy storage is a big deal in Texas, and it has the potential to grow into a sizable market. As the biggest electricity consumer of all U.S. states, Texas is working toward opening its markets to energy storage technologies and services. The Texas Energy Storage Association (TESA)—which advocates storage in ERCOT (Electric Reliability Council of Texas) and other Texas markets—supports legal and policy milestones and strategic energy storage projects. While Texas has yet to enact statewide storage regulations, they’re definitely on the horizon.</p>
<p>With TESA’s support, Texas passed a landmark bill in 2011 that defines energy storage, including batteries and flywheels, as generation when offering services on the competitive market. One of the law’s core goals is facilitating the interconnection process for energy storage resources by ensuring that they have the same status and benefits as traditional generation when connecting to the grid. As a big first step toward bringing storage into the fold, the law aims to enhance the reliability and efficiency of Texas’s grid, enable smoother integration of renewables, and reduce carbon emissions. In addition, the Texas PUC is in the process of adopting rules for the settlement and allocation of costs for storage. The commission also is considering granting ERCOT the authority to waive specific protocol requirements for demonstration projects of new technologies and services.</p>
<p>For its Notrees wind farm in West Texas, Duke Energy received a DOE grant under the <i>American Recovery and Reinvestment Act</i> (ARRA) of 2009. Notrees is one of the nation’s first storage projects at a utility-scale wind plant. Duke is matching DOE’s $22 million ARRA grant to develop and install a large-scale battery system (36 MW, 24 MWh) for storing renewable energy at this 153-MW, 95-turbine plant. Duke chose a Texas-based manufacturer for the project’s ultra-capacitor battery solution. The battery will store excess wind energy, manage intermittency, supply energy during peak demand periods, and stabilize grid frequency. Duke is also working with ERCOT to integrate the system with Texas’s grid. The utility expects the system to be in service by the end of 2012.</p>
<p>Texas already deployed the nation’s biggest sodium-sulfur (NaS) battery, which can power 4,000 residents in Presidio, Texas, for up to eight hours during an outage. Due to the town’s tenuous grid connection, outages are common in Presidio, which sits at the end of a 60-mile-long transmission system built in the 1940s. Although the aged line is expected to be replaced, residents have welcomed the giant 4-MW battery as reliable backup in an area susceptible to electrical storms. Developed by Japan’s NGK, the utility-scale battery responds swiftly enough to handle voltage fluctuations and momentary outages.</p>
<p>The $25 million energy storage installation is part of a larger $70 million project by Electric Transmission Texas, a joint venture of American Electric Power (AEP) and MidAmerican Energy Holdings subsidiaries, to improve transmission reliability surrounding Presidio. S&amp;C Electric Co.’s PureWave Storage Management System allows the utility to control the system, including storing grid power and dispatching it back to the grid as needed. This is the first time a state PUC has allowed rate-based recovery for a distributed energy storage project.</p>
<h4>New York’s Diverse Achievements</h4>
<p>From reducing regulatory burdens on clean energy plants to the governor’s funding of energy storage development, New York demonstrates diversity and leadership in legislation, regulation, and R&amp;D. The New York Battery and Energy Storage Technology Consortium (NY-BEST), a dynamic coalition of academia, entrepreneurs, industry, and federal advocates, continues spearheading numerous efforts to accelerate adoption of storage technologies statewide.</p>
<p>At the end of 2011, Governor Cuomo granted NY-BEST $15 million for battery and energy storage R&amp;D. He has also allocated $1 billion for developing an “energy superhighway” to deliver power, including renewable energy, from upstate and western New York to urban and downstate areas. These initiatives strongly support storage development, deployment, and commercialization efforts. Allocated funds target commercialization of advanced materials, fuel cells, and batteries for the state’s grid.</p>
<p>On the legislative side, New York recently approved a law supporting swifter deployment of all energy storage types by reducing regulatory burdens. The law added energy storage devices, including batteries, flow batteries, flywheels, compressed air energy storage (CAES) systems, and other storage devices to the definition of “alternative energy production,” exempting plants smaller than 80 MW from regulation by New York’s PUC. The law lets these facilities make frequency regulation services available sooner to stabilize the state’s grid. It also paves the way for them to provide additional ancillary services and grid-connected storage. By reducing regulations on clean energy plants, the law promotes storage of renewable energy generated off-peak for use during peak periods, increasing grid reliability and stability.</p>
<p>Additional legislation, currently under consideration in New York, would encourage further development of the energy storage sector by providing a significant tax credit to eligible companies of 20 percent for research and development and manufacturing property, and 10 percent for qualified R&amp;D expenses.</p>
<p>From battery storage to CAES, the New York State Energy Research and Development Authority (NYSERDA) funds diverse large- and small-scale storage projects statewide. In 2011, New York State Electric &amp; Gas (NYSEG), a subsidiary of Iberdrola USA, received $1 million from NYSERDA to explore applications of CAES as a green, reliable, economical generation source. Partly funded by DOE’s ARRA stimulus and smart grid grants, the project uses a depleted underground salt cavern near Watkins Glen to store up to 150 MW (two to eight hours or more) of compressed air energy for peak load and other applications. This project uses a smart grid control system for fast-response grid stabilization and to enable integration and storage of wind and other renewables. The facility could be operational and grid-connected by late 2014 or early 2015.</p>
<p>With support from NYSERDA, Beacon Power’s precedent-setting 20-MW flywheel energy storage plant in Stephentown, N.Y., exemplifies how storage performance can excel over traditional generation assets. Providing rapid-response frequency regulation service to New York’s grid, Beacon’s plant has increased grid reliability and cut carbon emissions by reducing dependence on fossil fuels. Its performance has influenced both regulatory and legislative initiatives.</p>
<p>In New York, Beacon’s innovation is complemented by that of AES Energy Storage, which owns and operates an 8-MW lithium-ion battery plant in Johnson City. The first plant of its kind in the U.S., this energy storage system provides extremely rapid grid-stabilizing frequency regulation services to New York Independent System Operator (NYISO). The system is being expanded to 20 MW, aided by a DOE loan guarantee of more than $17 million.</p>
<h4>Beyond Renewables Integration</h4>
<p>Energy storage is critical to the future of the nation’s grid. While integrating renewables is one essential application, with more legislative and regulatory support, storage can be leveraged in numerous ways to meet today’s energy demands. Storage can equip the grid for changes in consumer behavior. Increasing adoption of PEVs and smart appliances, decreased customer tolerance for outages, and the need to protect more sensitive electronics are a few ways consumers drive the need for storage.</p>
<p>Energy storage also can help electric utilities meet a wide array of power system goals, while delivering a significant return on investment. The power conversion electronics used with storage devices can be used to improve power quality and reliability, meet peak load demands, support grid optimization through improved voltage and reactive power (VAR) control, and provide frequency regulation and other grid ancillary services. They can also reduce carbon emissions and allow utilities to defer major capital investments for new infrastructure.</p>
<p>Currently, the U.S. maintains approximately 1,000 GW of installed generating capacity. According to the Electric Power Research Institute, more than 25 percent of distribution grid capacity and assets and 10 percent of transmission systems are needed to meet less than 400 hours of peak load demand annually. Traditional fossil-fuel plants are designed to meet peak load demands, which occur infrequently, rather than to meet average use. Plants must operate at 100 percent capacity when needed—such as during heat waves when air conditioners run 24x7. But peak periods are fleeting. Most of the time, plants operate at much lower capacities. Average electricity consumption is about 48 percent of peak generating capacity.</p>
<p>For managing peak loads, energy storage can be much more efficient than traditional fossil fuel plants, which are expensive to construct and operate and emit greenhouse gases. Instead of siting a new 100-MW power plant or paying premiums for peaker plant operations to meet demand for a few hot weeks in the year, a utility could supplement smaller distributed plants that meet average use requirements with energy storage that meets peak demands.</p>
<p>Bulk energy storage also can be part of the solution. In the U.S., pumped hydroelectric storage supplies 22 GW, comprising roughly 2 percent of all generation—a number that actually exceeds the combined wind and solar energy delivered to the grid today. However, siting hydro plants is often difficult due to the special geographic conditions required. Long-term, a more viable option for grid-scale storage is CAES, which can supply hundreds to thousands of megawatts at low cost, particularly when tied to wind energy, which can be stored in CAES reservoirs for peak periods.</p>
<p>Distributing energy storage systems throughout the grid is essential for more reliable, efficient systems with added capacity where needed. Distributed storage encompasses smaller systems not characterized as centralized generation. From new battery technologies to thermal energy storage, new and improved forms of distributed storage are becoming more readily available due to many factors, including government funding, legislation, and growing demand for clean, grid-tied energy.</p>
<p>One of the newest and most noteworthy is community energy storage (CES), which provides reliable local backup power and grid support, at the very edge of the distribution network. Small pad-mounted units, CES systems are easily dispersed throughout distribution grids, on street corners and utility rights-of-way. Units are typically rated 25 kVA and provide one to three hours of battery storage for multiple homes. With the proliferation of grid-tied rooftop photovoltaic (PV) panels and plug-in electric vehicles, utilities are challenged to control the voltage across local feeders, particularly as PVs increase load intermittency on circuits, and as charging PEVs add step increases to normal load patterns. By aggregating a number of grid-connected CES units, utilities can increase voltage control, manage peak loads, and integrate local renewables. As a result, CES adds a new layer of intelligence to the distribution system.</p>
<p>Another relatively new storage innovation is thermal energy storage, a system that uses standard HVAC systems at night to generate and store energy as ice or cold water, which is then used during peak demand times the following day. Thermal systems can be grid-connected, utility-controlled, and scaled for commercial and residential buildings. Precise control of electric water heaters is yet another way to help manage peak demands.</p>
<h4>Evolving Battery Technologies</h4>
<p>Batteries might hold the greatest potential for reliable, cost-effective, grid-tied energy storage. That’s why DOE is directing significant funds into improving battery technologies and accelerating development of new types. A large need exists for next-generation storage materials that improve battery performance, minimize costs, and speed market adoption of emerging technologies. From versatile lithium-ion to reinvented sodium-nickel chloride, batteries facilitate use of storage in a growing array of applications, including stationary grid-tied storage, power backup, and PEVs. Over the last two decades, three basic battery chemistries have undergone the most development and deployment: lithium-ion (Li-ion), sodium-sulfur (NaS), and flow batteries.</p>
<p>Li-ion is still the world’s fastest evolving battery technology with the broadest range of applications, including off-grid PEV charging, grid-scale storage, community energy storage systems, uninterruptible power supplies, peak shaving, and frequency regulation. Offering the most energy density for its weight, Li-ion can be applied in many shapes and sizes and is environmentally safe. Li-ion is being improved constantly; its only downsides are higher cost and some capacity deterioration. However, its cost is expected to drop over time as production volume increases due to the growing PEV market.</p>
<p>Invented in 1966 by Ford Motor Co. with hope for future electric vehicle applications, NaS batteries were enhanced over the last decade for large-scale grid storage applications. While high operating temperatures preclude some uses, these high-energy-density batteries provide the lowest cost per kilowatt hour, durability, and a 6-hour cycle time. MW-scale NaS batteries provide load leveling and standby power, and stabilize renewable power fluctuations. In Japan, giant NaS batteries, co-developed by NGK and Tokyo Electrical Power, have been widely deployed as grid storage for years. The world’s largest battery system, NGK’s 34-MW NaS battery in Rokkasho, provides 204 MWh of backup power for a 51-MW grid-tied wind plant.</p>
<p>Unfortunately, in September 2011, a large NaS battery in Japan caught fire, resulting in the shutdown of most NaS battery installations worldwide. In a massive undertaking, NGK now plans to rework all existing NaS installations to ensure the safety of each site.</p>
<p>Flow batteries, invented for NASA, provide rechargeable storage where electrolytes flow through power cell membranes to collect electrons. They are relatively low in cost, scalable by adding storage tank capacity, and not temperature-sensitive. Packaged flow batteries are increasingly used for grid storage and managing renewable energy intermittency, as well as remote applications, such as photovoltaic support systems and cell towers. Several manufacturers in the U.S., Australia, and China offer a variety of packaged solutions.</p>
<p>Major R&amp;D investment continues in a variety of battery chemistries, including sodium-nickel chloride (NaNiCl), which is similar to the NaS battery but has a smaller footprint. NaNiCl is geared to utility applications requiring three or more hours of discharge time. Major players, such as GE and Fiamm Group in Italy, are making serious moves to enter this market. Traditional lead acid battery manufacturer East Penn has invested in advanced lead acid and ultrabattery technologies, which are currently being deployed in renewable integration projects for both wind and solar. Sizable investments are also being channeled into rechargeable zinc air batteries, which hold significant promise for long discharge times of more than six hours, at a low unit cost.</p>
<p>Through its research arm, ARPA-E, DOE has funded R&amp;D supporting an array of new battery chemistries with great potential. One of the most notable is the sodium-ion battery, which will provide lower cost grid-scale storage with extended discharge times. Sodium-ion production is expected to begin in 2013. Another pivotal battery technology is liquid metal. Invented at MIT, liquid metal batteries promise very large-scale, low-cost storage for the electric grid.</p>
<h4>A Global Effort</h4>
<p>Energy storage is essential to the development of a truly effective smart grid. This realization is driving progress on multiple fronts nationwide. While legislative and regulatory barriers are beginning to break down, quantum leaps in policy and R&amp;D are still needed. More collaborative efforts among industry, government, and advocacy organizations are imperative to realizing the full potential of energy storage technologies for our electric grid. More strategic laws and incentives would help level the playing field and accelerate R&amp;D and deployment. And, more application data is needed to demonstrate the effectiveness and future potential of energy storage. Federal regulatory milestones, such as FERC 755, and more state-level policies—or less, in some cases—also will continue to fuel energy storage development and market growth.</p>
<p>Fortunately, because DOE leadership recognizes the importance of energy storage, the agency continues to press for improved technologies and swifter deployments, despite the up-front and early adoption costs of some storage types. At the same time, supporters of increased natural gas utilization point to cost as the primary barrier to the evolution of our smart grid. But the need to reduce greenhouse gas emissions can’t be ignored, and energy storage will play a growing role in this global effort as its initial costs decrease over time. Finding a way to balance these disparate forces now will help ensure the smoothest path to a smarter, more reliable, economical, and efficient grid. This balancing act will demand broader-scale integration of energy storage technologies with traditional assets.</p>
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Tue, 01 May 2012 04:00:00 +0000puradmin13394 at http://www.fortnightly.comThe Trouble with Freeridershttp://www.fortnightly.com/fortnightly/2012/03/trouble-freeriders
<div class="field field-name-field-import-deck field-type-text-long field-label-inline clearfix"><div class="field-label">Deck:&nbsp;</div><div class="field-items"><div class="field-item even"><p>The debate about freeridership in energy efficiency isn’t wrong, but it is wrongheaded.</p>
</div></div></div><div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Hossein Haeri and M. Sami Khawaja</p>
</div></div></div><div class="field field-name-field-import-bio field-type-text-long field-label-inline clearfix"><div class="field-label">Author Bio:&nbsp;</div><div class="field-items"><div class="field-item even"><p><b>Hossein Haeri</b> is executive director and <b>M. Sami Khawaja</b> is senior vice president at The Cadmus Group. The authors acknowledge the research assistance of Seth Kadish of The Cadmus Group.</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - March 2012</div></div></div><div class="field field-name-field-import-image field-type-image field-label-above"><div class="field-label">Image:&nbsp;</div><div class="field-items"><div class="field-item even"><img src="http://www.fortnightly.com/sites/default/files/article_images/1203/images/1203-FEA2-fig1.jpg" width="1372" height="2805" alt="" /></div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p>The energy efficiency programs administered by California’s investor-owned utilities reported 6,500 GWh of electricity and 84 million therms of natural gas savings for the three-year program cycle from 2006 to 2008. Yet valuations of these programs later credited the utilities for less than two-thirds of the electricity and slightly more than just one-half of the natural gas savings the utilities claimed. The rest—2,400 GWh and 40 million therms, to be exact—was claimed by freeriders.</p>
<p>And for the next three-year program cycle, from 2010 to 2012, California utilities appear set to invest $3.1 billion from 2010 to 2012 to meet the saving targets, 6,965 GWh and 153 million therms, approved by the California Public Utilities Commission (CPUC).<sup>1</sup> However, if things go as they did before—and indications are that they might—much of these savings will again go to freeriders.</p>
<p>Investment in energy efficiency has been growing rapidly throughout the United States. In a recent report, the Consortium for Energy Efficiency (CEE) estimated that spending on ratepayer-funded energy efficiency programs was $5.3 billion in 2009, with planned expenditures of 6.6 billion in 2010.<sup>2</sup> More than 50 percent of the expenditures were concentrated in California, New York, Massachusetts, and the Pacific Northwest—a group of states that accounts for 20 percent of U.S. electricity and natural gas consumption. Expenditures are also growing geographically, as the number of states offering energy efficiency programs has increased from 37 to 46 in just the past three years.</p>
<p>This trend is likely to continue for at least the near future. Energy efficiency resource standards with aggressive saving targets are in effect in 26 states and probably will be put into place in more states through legislative action, regulatory mandates, or voluntary goals. Program administrators in these states are accelerating their programs to meet mandated saving goals. As these programs expand and investments in them increase, so will concerns about how freeriders factor into success and compliance metrics. And mechanisms for performance risk and reward appear even more controversial.<sup>3</sup> As a result, freeridership likely will continue playing a prominent part in the regulatory and policy discourse about ratepayer-funded conservation.</p>
<p>Signs suggest a coming shift in the focus in energy efficiency, from energy resource planning to greenhouse gas emission reductions. As the goals of the two policies converge, questions arise about how to track and appropriately credit energy savings attributable to a myriad of different programs, such as 1) the regional greenhouse gas initiatives, 2) regional market transformation initiatives, 3) the federal <i>American Recovery and Reinvestment Act</i> (ARRA), 4) state tax policies to promote energy efficiency, and 5) local stimulus funds earmarked for energy efficiency and creation of green jobs. Such questions will only intensify the debate over freeridership, and about monitoring and attributing savings.</p>
<h4>The Origin of the Species</h4>
<p>Freeridership is a long-standing issue in all areas of social science that involve public policy. Russell Hardin, in the <i>Stanford Encyclopedia of Philosophy</i>, traces the origins of the concept to <i>Plato’s Republic</i> and points to references to it in the works of the 18th and 19th century political philosophers, including David Hume and John Steuart Mill, among others. As Hardin points out, despite this widespread recognition, it wasn’t until 1965 that the concept of freeridership and its implications for public policy were systematically formulated by Mancur Olson in his <i>Logic of Collective Action</i>. <sup>4</sup></p>
<p>Olson’s analysis was based on Paul Samuelson’s theory of public goods. Samuelson, in 1954, noted that some goods, once they’re made available to one person, can be consumed by others at no additional marginal cost.<sup>5</sup> This condition, called “jointness of supply” or “non-rivalrous consumption,” refers to situations where consumption of a good by one person doesn’t affect others’ consumption of the good. In other words, the good, once provided for anyone, “is <i>de facto</i> provided for everyone in the relevant area or group.”<sup>6</sup></p>
<p>A second distinctive feature to Samuelson’s theory of public goods is the impossibility of exclusion: Once a public good is supplied at all, excluding anyone from its consumption is supposedly impossible.<sup>7</sup> This attribute gives rise to freeridership, whereby some individuals either consume more than their fair share of a common resource, or pay less than their fair share of its costs. In certain cases, individual consumers may reap benefits without paying for them.</p>
<p>A compelling case exists that some goods are both joint in supply and non-excludable—the so-called “pure public goods,” such as clean air. But ratepayer-funded energy efficiency programs don’t fit this category, at least not closely, for they lack both of the defining features of a public good. They are hardly non-rivalrous, as there have been many cases of budget constraints prohibiting some eligible consumers from participating in a program. Nor are they non-excludable, since utilities routinely set eligibility criteria for participation, and enforce those criteria when possible.</p>
<p>Indeed, the logic of public goods is of little practical relevance in the context of ratepayer-funded energy efficiency. In these cases, freeridership refers to program participants who presumably would have conserved regardless of the program. These consumers are presumed to be predisposed to conservation; they practice efficiency whether or not any incentives are available. As such, they’re the opposite of what Samuelson would have considered freeriders: people unwilling to pay for a good while enjoying its benefits. Early adopters of energy efficiency and renewable technologies are a case in point.</p>
<h4>Cause and Effect</h4>
<p>The fundamental problem with freeridership in energy efficiency is attribution; that is, whether and to what extent the observed change in energy consumption or the adoption of an energy-efficient product is likely to have been triggered by a program. And the problem is by no means peculiar to energy efficiency. It arises in many policy areas, whenever economic agents are paid an incentive to do what they might have done anyway. The problem is inherent, for example, in the additionality requirement, which is the defining characteristic of the CO<sub>2</sub> offset concept established by the clean development mechanism (CDM) of the Kyoto Protocol. The mechanism, which is now the world’s largest greenhouse gas emissions offset scheme, is intended to validate and measure impacts from projects to ensure that they produce authentic benefits and are genuinely additional activities that wouldn’t otherwise have been undertaken.</p>
<p>In energy efficiency, freeridership factors into the calculation of a program’s impacts as the ratio of savings attributable to the program (net savings) and the savings expected to be achieved according to planning assumptions (gross savings). The result is the net-to-gross (NTG) ratio.<sup>8</sup></p>
<p>For utilities administering ratepayer-funded programs, the implications of NTG calculations can be large and wide-ranging. The calculations affect nearly all essential criteria that define and determine performance, particularly saving claims and cost-effectiveness. Uncertainty arises because the NTG ratio usually isn’t known until well after a program has been implemented. Utilities become exposed to financial risks, particularly in jurisdictions where performance standards include penalties for under-performance (<i>e.g.</i>, Pennsylvania, New York, and Washington), provisions for lost-revenue recovery (<i>e.g.</i>, Nevada and North Carolina), or shareholder incentive (<i>e.g.</i>, California and New York).</p>
<p>For these reasons, the concept of freeridership has been a uniquely charged topic, eliciting frustration and disagreement among energy-efficiency policy makers, program administrators, and evaluation experts. Despite years of research, no commonly held or precise understanding has been established of what NTG means, what it includes, how best to measure it, and what to do with the results once the measurement is done. In fact, its very definition isn’t firmly settled <i>(see “From Gross to Net.”)</i></p>
<p>Freeridership, and the broader concept of NTG, remain, in the words of William Saxonis, a regulator in New York, a “regulatory dilemma.”<sup>9 </sup></p>
<p>Freeridership remains the most common criticism of ratepayer-funded energy efficiency among the skeptics,<sup>10</sup> along with the so-called rebound effect (the notion that greater efficiency leads to increased consumption due to an income price effect) and persistence of savings. The debate over these topics dates back to the mid-1980s, when energy efficiency consisted of what were, by today’s standards, small-scale conservation programs focusing mostly on residential weatherization. Citing freeridership as an argument against public intervention in energy-efficiency markets, the critics of ratepayer-funded conservation argued that the presence of freeridership overstates the energy-savings potential of conservation programs and understates their actual cost, distorting resource choices.</p>
<p>Skeptics have criticized ratepayer-funded conservation on the grounds of distributional concerns arising from the potentially adverse rate impacts.<sup>11</sup> Because freeridership is correlated with the level of financial incentives available to the participant, the reasoning goes, if incentives are too high and the participant isn’t expected to commit his or her own money to the effort, freeridership will go up, reducing the effectiveness of the program and leading to higher average rates for consumers, particularly those who don’t benefit from the program.<sup>12 </sup></p>
<p>This argument sounds right, but is wrong. Free riders in energy efficiency programs tend to be those willing to adopt a measure with low (not high) incentives, relative to a measure’s incremental cost. These are the consumers who most likely would have adopted the energy efficiency on their own. This negative correlation between freeridership and incentives was amply demonstrated in a recent study in Washington. The study surveyed about 350 consumers who had participated in eight conservation programs that offered different levels of incentives. Participants were asked a number of questions on why they took part in these programs. Based on their answers, each respondent was assigned a freeridership score. A comparison of these scores with the incentives received by the respondents showed a strong negative correlation between ridership and incentives.<sup>13</sup></p>
<p>An element of equity does come into play in ratepayer-funded conservation. Any disparity between how benefits and costs are distributed among customers is important; If a customer enjoys the benefits of conservation, one might wonder why the bill for those services should be divvied up and sent to his neighbors, especially if he was willing to pay for them. However, in the context of ratepayer-funded conservation, freeridership is probably less about fairness and more about economic efficiency.</p>
<p>The economic efficiency argument was first formulated systematically in 1992 by Paul Joskow and Donald Marron.<sup>14</sup> In their analysis of data on 16 utility-sponsored conservation programs, the authors identified freeridership as one of the most important issues in determining the costs and valuing the benefits of conservation programs. The particularly remarkable aspect of the study was its characterization of freeridership as a dynamic problem. The problem, they argued, derives from the fact that freeridership isn’t limited to consumers who would have adopted energy-efficiency measures without the utility program, but also involves consumers who are likely to adopt the measures in the future.</p>
<p>From this perspective, a conservation program merely speeds up the adoption of energy-efficiency measures and increases the maximum penetration the measures are likely to achieve. Freeridership, therefore, isn’t merely a question of “<i>whether</i> some of this year’s participants would have adopted a conservation measure absent the utility’s program, but <i>when</i> they would have adopted the measure.”<sup>15</sup> Thus, if all of the participants would have installed the measure at some point in the future whether the program existed or not, “the static approach significantly overstates the actual savings of the program.” The failure to account for such dynamic diffusion effects, they argue, results in overestimating the savings and underestimating the cost of conservation.</p>
<p>This argument is true, but only partly. Rather, it only applies to programs involving a retrofit—replacing functioning equipment with more efficient equipment. It doesn’t apply to programs that offer incentives for replacement of equipment on burnout, a significant part of today’s portfolios of ratepayer-funded programs. In these cases, if the failed appliance isn’t replaced with an energy efficient one at the time of its replacement, the opportunity to do so will be lost for the course of the equipment’s useful life.</p>
<p>The argument is also one-sided. It places the emphasis on the acceleration component of diffusion and ignores the potentially large effects of conservation programs on shifting the curve. What if the services offered under a program induced participants to take further conservation actions? What if they encouraged other consumers to adopt conservation measures without taking advantage of the program’s incentives? They might take action because the program changed their perceptions about the benefits of conservation, or because the increase in demand induced a shift in supply, making energy-efficient products more available.</p>
<p>These behavioral effects on participants (participant spillover) and consumers in general (non-participant spillover or market transformation), although they’re hard to quantify, can be sizable. Joskow and Marron recognized the validity of this proposition, but didn’t explicitly account for these effects in their analysis.</p>
<h4>Motivation and Social Desirability</h4>
<p>A variety of methods have been used to either measure or account for freeridership. These methods fall into one of two general categories. The first is the general difference-in-differences approach, which involves comparing actual energy consumption of participants before and after they participate in a program to change consumption among a comparable group of non-participants in the same period.</p>
<p>Implemented properly and with a well-chosen comparison group, this quasi-experimental research design produces reasonably reliable results for net savings, but doesn’t provide separate estimates for the components of NTG, freeridership, spillover, and market transformation effects, individually. The method is often implemented using regression-based techniques to control for residual difference between the two groups, evaluate the sensitivity of savings to various factors, and estimate savings for individual measures for programs that bundle measures.</p>
<p>The main limitation of this approach is that it isn’t well suited for measuring savings for programs involving large commercial and industrial consumers. These consumers tend to be unique in many ways, identifying a comparable group of non-participants is often impractical. Savings, relative to total consumption, may also tend to be too small to measure against the many unpredictable factors that affect energy consumption of these consumers. It’s also less effective in new construction programs, where the lack of pre-program data doesn’t allow a complete comparison.</p>
<p>The second, and by far the more commonly used, group of methods rely on “self-report.”At a basic level, self-report involves asking participants a series of questions about what they would have done in the absence of the program. Responses are then scaled, weighted, and combined to produce a composite freeridership score (or index) for each respondent. The scores for individual respondents are then weighted (by their savings) and averaged to produce a program-level freeridership fraction.</p>
<p>The obvious limitation of the self-report approach is that it doesn’t produce an NTG ratio. Other components of NTG—spillover and market transformation effects—have to be estimated separately and then factored into the calculations. But eliciting reliable information about intentions and motivations can be thorny.</p>
<p>Using surveys to assess freeridership also raises concerns about response bias, particularly those biases involving social desirability, which is the tendency of respondents to gauge their responses to conform to socially acceptable values. This issue is well recognized in social sciences, and it’s discussed in a vast body of academic and professional literature, including conservation program evaluation manuals.<sup>16</sup></p>
<p>One aspect of social desirability is the tendency of respondents to offer what they think is the right answer, and this tends to result in an overstatement of freeridership. Also, as some evaluation experts have noted, people have internal reasons—as explained by social psychology’s attribution theory—that motivate them to make certain decisions and to follow a cognitive process for justifying those decisions.<sup>17 </sup></p>
<p>Survey design practices have improved, and sophisticated ways of designing questionnaires promise a more nuanced way of eliciting information more reliably. Instead of simply asking what participants would have done in the absence of the program, multiple questions probe respondents about timing (would they have adopted the measure at the same time), amount (would they have adopted the measures in the same quantity), and level (would they have adopted the measures at the same level of efficiency).</p>
<p>What questions to ask, what kind of scale to use for recording responses, what weights to consider appropriate, and how to apply the final scores are decisions that expose the analysis to subjective judgment.<sup>18</sup> This problem could make the analysis a subjective exercise, open to constant dispute. Different evaluations of similar programs conducted by analysts using seemingly similar methods have produced drastically different results. The use of surveys for determination of spillover effects, for participants or non-participants, is especially sensitive to variances in spillover scores. Small fractions multiplied by very large numbers of customers can dramatically boost the savings.</p>
<p>Another—and less tractable—aspect to response bias is construct validity, which raises questions about what the survey results actually measure. The problem stems from the fact that survey respondents are naturally predisposed to conservation; After all, they are program participants. Thus, it remains far from clear whether their responses are conditioned by the effects of the conservation program itself.</p>
<p>The survey results would overstate freeridership because the survey may be asking the question from the wrong people: those identified as freeriders are, in fact, exactly the type of participants program administrators would want for a program.<sup>19</sup> What’s being measured, it appears, are the effects of the program—not what would have been expected in its absence.<sup>20</sup> In areas with long histories of conservation programs and activities, it’s no longer possible to parse out who is a freerider and who was influenced by the program.</p>
<p>Could it be that, in the case of such transformed markets, what’s being measured in freeridership surveys is in fact the opposite: spillover?</p>
<p>Considerable practical matters limit the usefulness of self-report as a means of eliciting information about freeridership in upstream, mass-market programs, where it might not be possible to identify participants, let alone freeriders, because consumers might not be aware that the price they pay for a product includes a utility discount. This happens routinely in programs that offer point-of-sale incentives for products such as compact fluorescent light bulbs.</p>
<p>The use of self-report is even more problematic in the large commercial, industrial, and new-construction sectors, where investment decision-making processes are complex and finding the right people to survey is rarely easy. Using the method is even more problematic in upstream programs deployed through retailers, where purchasing and stocking decisions can be especially complex, particularly in chains, where decisions tend to be made centrally and based on competitive considerations.</p>
<p>Self-report remains the most common method for determining freeridership. The approach has been defended by its protagonists as a transparent and appropriate approach for evaluating complex and diverse programs and markets.<sup>21</sup> They have argued that the method’s shortcomings are mostly a matter of misunderstanding and misapplication,<sup>22</sup> and that the noted biases are readily addressed through improved survey design, better scaling algorithms, and analytic techniques.<sup>23</sup></p>
<p>A report produced by an independent evaluator in 2006, summarizing the results of recent programs in California, noted that “the issues of identifying freeriders are complicated and estimating reliable program-specific freeridership is problematic at best.”<sup>24</sup> One year later, the California Public Utilities Commission formed a working group of experts to explore ways to improve the self-report method and produce standardized questionnaires to collect the data and algorithms to analyze them consistently. The result was 17 recommendations that were largely useful but somewhat too general to address the fundamental shortcomings of the approach.<sup>25</sup></p>
<p>A 2011 study commissioned by the Association of Energy Efficiency Program Administrators in Massachusetts developed survey instruments to assess freeridership and spillover in the commercial and industrial sectors. These instruments go a long way toward standardizing the data collection, scoring, and analytic steps. <sup>26</sup> The study concludes that the self-report techniques are “based on sound methodologies and are consistent with analytical methods used in the social sciences.” But the study doesn’t satisfactorily address the essential questions of response bias.</p>
<h4>Baseline and Spillover</h4>
<p>Related to the measurement problem is an idea advanced by some energy-efficiency planners. Freeridership, they say (and NTG, too), is essentially a question about baseline. “Counterfactual” is another way to put it: that is, the conditions that might have existed in the absence of a program.</p>
<p>As the argument goes, if actual market conditions, instead of hypothetical conditions based on codes and standards, were used as the basis for calculating expected savings of conservation measures, the resulting estimates would then need no further adjustment.</p>
<p>True enough, the concepts of NTG and baseline are linked. The actual penetration of conservation measures is a reasonably strong indicator of what might have happened in the absence of a program—but only for a planned program. It doesn’t address the question of attribution in <i>ex post</i> evaluation of existing programs, because the observed market conditions also reflect not only a program’s known direct impacts, but also the effects it might have induced—in other words, spillover. Disentangling what might have occurred in the absence of a program from the program’s spillover effects is practically impossible in most cases. The longer a program operates, the more biased the estimates of freeridership are likely to be.<sup>27 </sup></p>
<h4>Policy Differences, State by State</h4>
<p>The definition, measurement, and treatment of freeridership, and NTG in general, vary across jurisdictions in the U.S. Some jurisdictions include both freeridership and spillover in their definitions of net savings, while others allow only freeridership to be counted. In several cases, freeridership and spillover are measured separately and incorporated in NTG, while other jurisdictions estimate NTG without specifying freeridership and spillover individually. In the majority of cases where NTG is required, it’s applied only prospectively for planning and improving program design.</p>
<p>A review of practices in 31 jurisdictions with active energy efficiency programs illustrates this variation. All but six of these jurisdictions (82 percent) have energy efficiency resource standards (EERS) in place, setting minimum performance requirements.<sup>28</sup> Remarkably, documents and reports are lacking on NTG or how it’s treated in different jurisdictions. For many jurisdictions, this information must be gleaned from multiple sources, such as regulatory filings and evaluation reports. Indeed the authors’ research couldn’t determine with certainty the requirements for calculating and reporting NTG in several jurisdictions.</p>
<p>The available information shows that 13 of the jurisdictions (42 percent) have no NTG requirements. 18 jurisdictions (58 percent) include freeridership in determination of NTG, and in seven of these jurisdictions freeridership is applied at the energy efficiency measure level. In six jurisdictions (20 percent) only freeridership in accounted for. Participant spillover is measured in 12 jurisdictions (37 percent) and in 10 cases (32 percent) NTG calculations include all three effects <i>(see Figure 1)</i>.</p>
<p>The high proportion of cases where only freeridership is assessed suggests an asymmetrical treatment of spillover and freeridership effects. Should spillover be included, it’s likely that many of the NTG ratios will be near or greater than 1.0. Over two-thirds of all evaluation studies reviewed in a recent best-practice study had a net-to-gross value of approximately 1.0.<sup>29 </sup></p>
<p>Finally, there are cases where NTG—or its components—don’t require measuring. Gross savings, adjusted for actual installation rates, are employed instead as the measure of program performance. That’s also the case with regional transmission organizations (RTO) such as the New England independent system operator (ISO-NE), where verified gross savings are used as the basis for verification of energy-efficiency bids into the forward energy market.</p>
<p>There’s also the question of what to do with the NTG ratio once it’s measured, and how to factor it into performance metrics, such as cost-effectiveness tests. Although the total resource cost test (TRC)—as formulated in the <i>California Standard Practice for Cost-Benefit Analysis of Conservation and Load Management Programs</i> (SPM)—has been almost universally adopted as the principal criterion for economic assessment of conservation programs, there was no clear or uniform method to how the NTG should be applied to the cost side of the TRC equation. Indeed it wasn’t until 2007, almost 25 years after the SPM’s initial publication in 1983, that the CPUC issued a memorandum to clarify the matter.<sup>30</sup> Even today there’s little consensus on how to account for NTG in the calculation of TRC.</p>
<h4>Assessing Blame</h4>
<p>It’s tempting to blame the critics of energy efficiency for the prolonged confusion over what to make of freeridership; and that wouldn’t be entirely wrong. But skepticism about ratepayer-funded conservation isn’t the full story. The fact is that the proponents of energy efficiency have failed to devise and make a convincing case for workable solutions to the problem.</p>
<p>In truth, the energy efficiency community holds no common view about a precise definition of what constitutes net savings or how to quantify it. Even the relevance of freeridership lacks consensus. Advocates of ratepayer-funded conservation have regarded freeridership as irrelevant and have dismissed it as a mere distraction.<sup>31</sup> Some skeptics, on the other hand, have singled out freeridership as a fundamental flaw in energy-efficiency policy; a byword for everything that’s wrong with ratepayer-subsidized conservation.</p>
<p>Freeridership and the broader question of attribution are legitimate concerns when ratepayer funds are used for what’s presumed to be a socially optimal outcome. Efficient allocation of resources must be a part of the process of making policy decisions and designing programs to implement them.<sup>32</sup></p>
<p>But the lack of progress and the resulting uncertainty have surely inhibited creativity and innovation in program design and delivery. Program administrators have tended toward risk aversion, encouraged to focus on performance targets and to avoid regulatory penalties, instead of experimenting with potentially better programs.</p>
<p>An even more important reason for taking these seemingly conceptual and methodological disagreements seriously is this: If the concept of NTG and its measurement are perceived by policymakers and much of the public as dubious and inherently problematic, then political support for energy efficiency and, critically, its role in addressing larger global environmental issues, could dissipate.</p>
<p>Of course, measuring program performance remains a challenge. The measurement of NTG remains, as some experts have noted, an art rather than a science. <sup>33</sup></p>
<p>But what if the measurement itself turns out to be the problem? Certainly, program administrators should avoid programs where freeridership is known to be high and discontinue offering the programs when high freeridership is suspected. But insisting on measuring freeridership with tools of questionable reliability isn’t the answer.</p>
<h4>A Modest Proposal</h4>
<p>Knowing whether a program is likely to attract freeriders may be easier than it’s made to appear. Simple rules might well do.</p>
<p>First, regulators could establish a series of hurdles, or tests, that a program has to pass to avoid high freeridership. The exact nature of the tests would vary depending on the program, but the amount of the incentive relative to the cost of the measure is a good general gauge. When very low incentives appear to attract a large number of participants, or net benefits to participants are very high, chances are the majority of participants will be freeriders.</p>
<p>Second, program administrators should monitor product markets closely to see if a transformation has occurred and exit the market when it has. Expected savings and costs of conservation measures should be revised periodically based on actual saturation of energy-efficient products. In this way, research and evaluation resources are invested in improving programs, rather than merely proving compliance.</p>
<p>For this approach to work, regulators would have to recognize such obvious, albeit hard-to-quantify, benefits, and be willing to credit program administrators with the results by lowering their saving targets accordingly, or even reward them. These ideas already seem to be taking hold in several states, where gross savings, adjusted for a deemed level of freeridership, are the basis for determining compliance and program performance. This sensible approach ought to address most of the concerns about freeriders. More importantly, it will encourage program administrators to undertake more optimal levels of energy efficiency and focus more on programs such as market transformation that might produce longer-lasting effects at potentially lower costs.</p>
<p>Well-conceived and effectively executed programs will likely generate enough spillover savings to offset freeridership. What few freeriders remain can be regarded, as one evaluation expert puts it, simply “a cost of doing business.”<sup>34 </sup></p>
<p> </p>
<h4>Endnotes:</h4>
<p>1. <i>Decision Approving 2010 to 2012 Energy Efficiency Portfolios and Budgets</i>, CPUC 09-09-047, California Public Utilities Commission, September 2009.</p>
<p>2. <i>State of the Efficiency Program Industry - 2009 Expenditures, Impacts &amp; 2010 Budgets</i>, Consortium for Energy Efficiency (CEE), Boston, December 2010.</p>
<p>3. For a discussion of risk-reward mechanism in California see Rufo, Michael, <i>Evaluation and Performance Incentives: Seeking Paths to (Relatively) Peaceful Coexistence, Proceedings, the International Energy Program Evaluation Conference</i>, Portland, Oregon, August 2009.</p>
<p>4. Hardin, Russell, “The Freerider Problem,” <i>The Stanford Encyclopedia of Philosophy</i> (Fall 2008 Edition), Edward N. Zalta (ed.).</p>
<p>5. Samuelson, P. A., “The Pure Theory of Public Expenditure,” <i>Review of Economics and Statistics</i>, 36, 387-389, 1954.</p>
<p>6. Hardin, Russell, Op. cit.</p>
<p>7. It’s been argued that exclusion is, more often than not, merely a problem of technology, not of logic. People are often easily excluded from enjoying public goods such as television broadcasting through the use of various devices that enable providers to charge the beneficiaries and to exclude those who don’t pay, as for example, service providers that use cable rather than broadcasting over the air to provide television programming at a substantial price.</p>
<p>8. In some jurisdictions NTG is defined more broadly and the difference between gross and net savings includes other factors such as spillover, price-induced, or naturally occurring conservation and, in the case of certain upstream programs, leakage: purchase of energy-efficiency products by consumers outside a program administrator’s service area.</p>
<p>9. Saxonis, William P., “Freeridership and Spillover: A Regulatory Dilemma,” Proceedings, <i>Energy Program Evaluation Conference</i>, Chicago, August 2007.</p>
<p>10. For a discussion of general criticism of energy efficiency see Geller, Howard, et. al., “The experience with Energy Efficiency Policies and Programs in IEA Countries, Learning from the Critics,” International Energy Agency Information, August 2005.</p>
<p>11. “Utility Energy Efficiency Programs: Too Cheap to Meter?” ELCON Policy Brief, Electricity Consumers Resource Council, December 2008.</p>
<p>12. It’s paradoxical that these concerns are often raised by industrial consumers, who have historically received at least a proportionate share of the conservation subsidies provided by utilities.</p>
<p>13. The Cadmus Group, <i>Net-to-Gross Evaluation of Avista’s DSM Programs</i>, Prepared for Avista Utilities, Spokane, Wash., April 2011.</p>
<p>14. Joskow, P.L. and D.B. Marron, “What Does a Negawatt Really Cost? Evidence from Utility Conservation Programs” <i>The Energy Journal</i>, 13(4): 41-74. See also Paul Joskow and Donald Marron, <i>What Does a Negawatt Really Cost? Further Thoughts and Evidence</i>, MIT-CEEPR 93-007WP, May 1993.</p>
<p>15. Ibid, p.47.</p>
<p>16. See, for example, “Guidelines for Estimating Net-To-Gross Ratios Using the Self-Report Approaches,” the Energy Division, California Public Utilities Commission, 2007.</p>
<p>17. For an ample discussion of this topic, see Peters, Jane S. and Marjorie McRae, “Freeridership Measurement Is Out of Sync with Program Logic … or, We’ve Got the Structure Built, but What’s Its Foundation?” <i>Proceedings, ACEEE Summer Study</i>, Monterey, Calif., August 2008.</p>
<p>18. For a discussion of how alternative scoring methods might alter the results, see Kenneth M. Keating, “Freeridership Borscht: Don’t Salt the Soup,” <i>Proceedings, International Energy Program Evaluation Conference</i>, Portland, OR, August 2009.</p>
<p>19. Peters, Jane S. and Marjorie McRae, op.cit.</p>
<p>20. Stern, Paul C., T. Dietz, T. Abel, G.A. Guagnano, L. Kalof, “A value-belief-norm theory of support for social movements: The case of environmentalism,” <i>Human Ecology Review</i> 6 (2).</p>
<p>21. Chappell, Catherin, et al., “Net Savings in Nonresidential New Construction: Is a Market Based Approach the Answer?” <i>Proceedings, International Energy Program Evaluation Conference</i>, New York, 2005.</p>
<p>22. Ridge, Richard, “The Origins of the Misunderstood and Occasionally Maligned Self-Report Approach to Estimating the Net-To-Gross Ratio,” <i>International Energy Program Evaluation Conference</i>, Portland, Ore., August 2009.</p>
<p>23. Erickson, Jeff and Mary Klos, “Freeridership: Arbitrary Algorithms vs. Consistent Calculations,” Proceedings, <i>International Energy Program Evaluation Conference</i>, Portland, Ore., August 2009.</p>
<p>24. TecMarket Works, California <i>2002-2003 Portfolio Energy Efficiency Program Effects and Evaluation Summary Report</i>, prepared for Southern California Edison Co., January 2006, p. 41, 68-69.</p>
<p>25. California Public Utilities Commission, <i>Guidelines for Estimating Net to Gross Ratios Using Self Report Approach</i>, CPUC Energy Division, October 2007.</p>
<p>26. Tetra Tech, <i>Massachusetts Program Administrators Cross-Cutting C&amp;I Freeridership and Spillover Methodology Study Final Report</i>, Prepared for Massachusetts Program Administrators, April 18, 2011, Revised May 20, 2011.</p>
<p>27. Friedman, Rafael, “Maximizing Societal Uptake of Energy Efficiency in the New Millennium: Time for Net-to-Gross to Get Out of the Way?” Proceedings, <i>International Energy Program Evaluation Conference</i>, Chicago, August 2007.</p>
<p>28. The surveyed jurisdictions were Arizona, Arkansas, California, Colorado, Connecticut, Delaware, District of Columbia, Florida, Hawaii, Idaho, Indiana, Iowa, Maine, Maryland, Massachusetts, Michigan, Minnesota, Nevada, New Hampshire, New Jersey, New York, North Carolina, Ohio, Oregon, Pennsylvania, Texas, Utah, Vermont, Washington, and Wisconsin.</p>
<p>29. Quantum Consulting (now part of Itron). This study was managed by Pacific Gas &amp; Electric under the auspices of the California Public Utility Commission in association with the California Energy Commission. The information from the study is available <a href="http://www.eebestpractices.com/index.asp" target="_blank">here</a>.</p>
<p>30. California Public Utilities Commission, <i>Standard Practice for Cost-Benefit Analysis of Conservation and Load Management Programs</i>, 1983, revised in 1988, 1992 and 2001. The Clarification Memorandum was issued by CPUC in 2007.</p>
<p>31. Heins, Stephen, “Energy Efficiency and the Spectre of Freeridership, Is a Kilowatt Saved Really a Kilowatt Saved?” Proceedings, <i>ACEEE Summer Study on Energy Efficiency in Buildings</i>, Monterey, Calif., August 2006.</p>
<p>32. Fagan, Jennifer, et.al, <i>A Meta-Analysis of Net to Gross Estimates in California</i>, Proceedings, Association of Energy Services Professionals Conference, 2009.</p>
<p>33. <i>Model Energy Efficiency Program Impact Evaluation Guide</i>, National Action Plan for Energy efficiency, November 2007, prepared by Schiller Associates, November 2007.</p>
<p>34. Personal conversation with Dr. Ben Bronfman, a member of the planning committee, the International Energy Program Evaluation Conference, and an Executive Director at The Cadmus Group.</p>
</div></div></div><div class="field-collection-container clearfix"><div class="field field-name-field-sidebar field-type-field-collection field-label-above"><div class="field-label">Sidebar:&nbsp;</div><div class="field-items"><div class="field-item even"><div class="field-collection-view clearfix view-mode-full field-collection-view-final"><div class="entity entity-field-collection-item field-collection-item-field-sidebar clearfix">
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<div class="field field-name-field-sidebar-title field-type-text field-label-above"><div class="field-label">Sidebar Title:&nbsp;</div><div class="field-items"><div class="field-item even">From Gross to Net</div></div></div><div class="field field-name-field-sidebar-body field-type-text-long field-label-above"><div class="field-label">Sidebar Body:&nbsp;</div><div class="field-items"><div class="field-item even"><!--smart_paging_autop_filter--><!--smart_paging_filter--><p>Freeridership—and the general issue of attributing observed results to program implementation—has long been recognized as a problem in ratepayer funded conservation. The problem is discussed thoroughly in early manuals for impact evaluation of conservation programs by the Oakridge National Laboratory<sup>1</sup> and the Electric Power Research Institute.<sup>2</sup></p><p>Conceptually, freeridership reflects an aspect of self-selection bias, a problem in voluntary programs under which participants may be propelled to adopt conservation measures by factors unrelated to a conservation program.</p><p>That places a premium on how NTG is defined, the net-to-gross ratio—the ratio of savings attributable to the program (net savings) versus the savings expected to be achieved according to planning assumptions (gross savings).</p><p>But no consensus exists on what NTG means and what its elements are. The lack of a common perspective was amply demonstrated in a 2010 scoping study sponsored by the New England Energy Efficiency Partnership (NEEP).<sup>3</sup> The study started with a survey of local experts in energy efficiency, asking them apparently simple questions: What are “net” savings? What are the elements of NTG? What’s the proper role of NTG in program evaluation? How should it be measured and what would be the appropriate amount that should be invested in measuring it?</p><p>It turns out that none of these questions has an obvious or easy answer. The study concluded that, even within a region with one of the longest histories of energy conservation, “the definition and measurement of net energy savings remains a controversial issue.” Even more surprising is that the experts could not even agree on whether more consistent definitions and measurement approaches were needed or even desirable. The lack of consensus was echoed in a 2007 survey of 20 energy efficiency program planners, implementers, and evaluators, carried out for the California Evaluation Outreach Initiative under the auspices of CPUC.<sup>4 –</sup><span><span class="bolditalic">HH and MSK </span></span></p><p> </p><p> </p><h4>Endnotes:</h4><p>1. <i>Handbook of Evaluation of Utility DSM Programs</i>, ORNL/CON-336, Oak Ridge National Laboratory, December 1991.</p><p> </p><p>2. <i>Impact Evaluation of Demand-Side Management Programs, Vol. 1: A Guide to Current Practice</i>, EPRI CU-7179, Electric Power Research Institute, Palo Alto, Calif., February 1991a.</p><p>3. <i>Evaluation, Measurement, and Verification Forum, Northeast Energy Efficiency Partnerships (NEEP), Net Savings Scoping Paper</i>, Prepared by NMR Group and Research Into Action, November 2010.</p><p>4. <i>Survey of Energy Efficiency Evaluation Measurement and Verification (EM&amp;V) Guidelines and Protocols and Gaps and Needs</i>, Schiller Consulting, Prepared for The California Evaluation Outreach Initiative, May 2007.</p><p> </p><p> </p></div></div></div> </div>
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Thu, 01 Mar 2012 05:00:00 +0000puradmin13415 at http://www.fortnightly.comGridlock in 2030?http://www.fortnightly.com/fortnightly/2012/01/gridlock-2030
<div class="field field-name-field-import-deck field-type-text-long field-label-inline clearfix"><div class="field-label">Deck:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Policy priorities for managing T&amp;D evolution.</p>
</div></div></div><div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Timothy D. Heidel, John G. Kassakian, and Richard Schmalensee</p>
</div></div></div><div class="field field-name-field-import-bio field-type-text-long field-label-inline clearfix"><div class="field-label">Author Bio:&nbsp;</div><div class="field-items"><div class="field-item even"><p><b>Timothy D. Heidel</b> is a postdoctoral associate, <b>John G. Kassakian</b> is professor of electrical engineering and computer science, and <b>Richard Schmalensee</b> is Howard W. Johnson professor of management and economics, all at the Massachusetts Institute of Technology (MIT). Kassakian and Schmalensee were co-chairs of the MIT <i>Future of the Electric Grid</i> study cited in this article, and Heidel was the study’s research director. Their colleagues involved with that study haven’t reviewed this article, so the authors acknowledge responsibility for its contents. A few years ago, former Secretary of Energy Bill Richardson characterized the U.S. electric grid, the system of physical and human systems linking generators to loads, as “third-world.”<sup>1</sup> More recently, others have claimed that smart grid technologies promise to “spur the kind of transformation the Internet has already brought to the way we live, work, play and learn.”<sup>2</sup></p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - January 2012</div></div></div><div class="field field-name-field-import-image field-type-image field-label-above"><div class="field-label">Image:&nbsp;</div><div class="field-items"><div class="field-item even"><img src="http://www.fortnightly.com/sites/default/files/article_images/1201/images/1201-FEA1-fig1.jpg" width="1020" height="811" alt="" /></div><div class="field-item odd"><img src="http://www.fortnightly.com/sites/default/files/article_images/1201/images/1201-FEA1-fig2.jpg" width="1024" height="868" alt="" /></div><div class="field-item even"><img src="http://www.fortnightly.com/sites/default/files/article_images/1201/images/1201-FEA1-fig3.jpg" width="1026" height="1093" alt="" /></div><div class="field-item odd"><img src="http://www.fortnightly.com/sites/default/files/article_images/1201/images/1201-FEA1-fig4.jpg" width="1018" height="745" alt="" /></div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p>A few years ago, former Secretary of Energy Bill Richardson characterized the U.S. electric grid, the system of physical and human systems linking generators to loads, as “third-world.”<sup>1</sup> More recently, others have claimed that smart grid technologies promise to “spur the kind of transformation the Internet has already brought to the way we live, work, play and learn.”<sup>2</sup></p>
<p>Over the next two decades, when technologies known today will still dominate the grid, are we condemned to a deteriorating future of rising rates and more frequent blackouts, or will available smart grid technologies transform our lives as thoroughly as the Internet has? Having just completed a two-year study of the future of the U.S. electric grid with a dozen other economists and engineers,<sup>3</sup> we have come to the conclusion that the grid’s future performance is far from predetermined; it will be shaped to a large degree by a few key choices made—or not made—at the state and federal levels and within the industry in the next few years.</p>
<p>To establish initial conditions, the available data don’t support the notion that the U.S. grid is failing or antiquated. Over time, the grid has incorporated several generations of new technologies, including higher transmission voltages and remote sensing equipment, to enhance its performance. Transmission and distribution losses have declined steadily over time <i>(see Figure 1) </i>and appear to be in line with losses in other developed nations. Available data don’t permit an accurate assessment of trends in reliability, however—even at the bulk power level, let alone at the level of the average consumer. International comparisons that can be made suggest that U.S. reliability levels are roughly in line with those elsewhere.</p>
<p>Decision-making processes would improve if regulators required the publication of data on reliability and other important elements of system performance, using standardized definitions that permit comparisons across space and time. Ideally, of course, the remuneration of public and private utilities and their managers would be explicitly linked to performance assessments.</p>
<p>On the other hand, while the next two decades likely will be a period of slow growth in U.S. electricity demand, public policies that enjoy widespread support and a variety of technological and economic changes will alter both the demand for and supply of electricity in challenging ways. Technologies exist that can meet these challenges effectively, but only if a number of regulatory policies are changed, necessary research and development is performed, and important data are compiled and shared. If these steps aren’t taken—and they seem far from inevitable—it might well be difficult to maintain both reliability and rates at acceptable levels.</p>
<p>An important challenge facing the electric power sector not discussed further in this article is the aging of its technical workforce, a problem made more serious by the decline in university power engineering programs. This problem is widely acknowledged; significant efforts are underway to deal with it; and we have no related recommendations to offer.</p>
<p>While we believe information technology has much to offer the grid, we avoid reliance on the term “smart grid” here and in our study’s report both because it means different things to different people and because increasing the grid’s intelligence is only one possible means to ends that include the reliable and economical provision of electricity. Moreover, while some smart grid technologies do make it possible for residential customers to be more active participants in electricity markets, few seem eager to devote more attention to a product that accounts for only a few percent of their monthly budgets. And, at the end of the day, we have seen no “killer electricity apps” on the horizon. If all goes well, turning on a lamp in 2030 will have the exact same effect it does today—and will require no more thought.</p>
<h4>Grid-Scale Variable Resources</h4>
<p>Current federal and state policies are tilting the playing field sharply in favor of renewable generation, and such support seems almost certain to continue. Thus wind and solar generation are almost certain to become more important by 2030—though perhaps not as important in many U.S. regions as they already are in some E.U. countries.</p>
<p>Two well-known features of these technologies pose potential problems for the electric grid. First, the output of wind and solar generators varies considerably over time and is imperfectly predictable. For this reason, they and some other technologies are labeled “variable energy resources,” or VERs. At high levels of VER penetration, demand minus VER generation—that is, the net load that must be met by other generators—becomes noticeably more variable and difficult to predict. To maintain reliability despite this variability, the system and its operation must be modified at some cost. Few incentives exist today in organized markets for investments that add generation flexibility or for operating in a flexible manner, for instance, even though power system flexibility will become more important as the penetration of VERs increases. Full or virtual consolidation of small balancing areas would facilitate VER integration, as would requiring new VER generators to meet performance specifications appropriate for operation in the high-VER future they likely will encounter.</p>
<p>Second, many of the most promising sites for wind and solar generators are distant from major load centers. Exploiting these sites will require building relatively more transmission lines that cross state borders or the 30 percent of U.S. land managed by federal agencies. These boundary-crossing lines face special problems related to planning, cost allocation, and siting.</p>
<p>When boundary-crossing lines are proposed today, they tend to be evaluated in isolation, not as part of a wide-area planning process, and allocation of the costs involved is often done via facilities-specific negotiations. FERC Order No. 1000, issued in July 2011, should significantly increase wide-area planning of transmission systems, make routine the allocation of the costs of boundary-crossing transmission facilities, and, by explicitly adopting the “beneficiaries pay” principle, rationalize the allocation of those costs. Grid efficiency would be further enhanced if the affected parties went beyond the order’s requirements and established permanent and collaborative planning processes at the interconnection level and developed a single cost allocation procedure for boundary-crossing projects in each interconnection. However, planning tools that can deal with complex networks taking uncertainty into account don’t exist today, and research to develop them is needed. For such research to be most productive, detailed data covering the major interconnections must be made appropriately available to researchers.</p>
<p>Under current law, states retain the primary role in siting transmission facilities, and their interests often conflict. Any involved state can block a multistate project. Moreover, federal agencies with missions that include purposes unrelated to energy can and do block or delay the construction of transmission lines across land they control. No agency is charged with considering the broad national interest. Boundary-crossing projects are thus particularly difficult to build, and the special difficulties involved will pose an obstacle to the efficient integration of grid-scale wind and solar generation. In recognition of this problem, the <i>Energy Policy Act</i> of 2005 contained a section that was intended to give FERC backup siting authority if states withheld approval of multistate transmission facilities in congested corridors, but subsequent court decisions have effectively annulled that section.</p>
<p>To deal with this problem, FERC needs effective siting authority over major boundary-crossing transmission facilities everywhere in the nation. Some have argued that in the interest of efficiency, FERC should have sole siting authority over these projects, as it does over interstate natural gas pipelines. Others contend that giving FERC backstop authority to site projects blocked or unreasonably delayed by states or other federal agencies would create a process more sensitive to states’ and other agencies’ legitimate concerns. While both approaches clearly have strengths and weaknesses, new legislation that adopted either would represent a significant improvement over the status quo.</p>
<h4>Peak Demand and Electric Vehicles</h4>
<p>Changes in the nature of electricity demand over the past several decades have produced a substantial increase in the ratio of power demand during peak hours to average demand—an increase in the peakiness of demand. Figure 2, which presents load duration curves for New England and New York expressed as percentages of peak hour demand, illustrates this increase. Because power systems need to be sized to meet peak demand with a margin for reliability, the peakier demand becomes, all else equal, the lower capacity utilization becomes, and thus the higher rates must become to cover all costs.</p>
<p>The increased penetration of air conditioning was likely an important contributor to these changes in the New York and New England region over this period. Elsewhere the relative decline of industrial load—from about half of total load in the 1950s to under 30 percent in the 2000s—might have played a more important role. These trends are likely to continue. And, although their penetration is generally projected to be slow at the national level, electric vehicles (EVs)—including plug-in hybrids and pure electric vehicles—could exacerbate these trends, even in the near term. EVs are expected to achieve substantial penetration quickly in some high-income areas with environmentally conscious consumers. Wherever they are deployed in large numbers, their impact on the grid will depend importantly on when they are charged. If they are charged when commuters return home, as seems most likely under current policies, they could add significantly to system peak loads, worsening the peak-load problem <i>(see Figure 2)</i>.</p>
<p>On the other hand, policy changes that encouraged overnight charging of EVs could increase demand when it would otherwise be low, thus tending to flatten load duration curves. Even greater savings might be realized by making other loads similarly responsive to system conditions. Since highly variable demand yields highly variable incremental energy costs, dynamic pricing—in which retail prices vary over short time intervals to reflect changes in the actual cost of providing electricity—is the most conceptually natural way to induce such responses. Most demand response programs in place today use other approaches and focus on response to occasional emergencies rather than systematic load-leveling. Existing studies suggest that regulators can achieve substantial load shifting—and perhaps overall demand reduction—when dynamic pricing is combined with the use of technology to automate response to price changes. Figure 3 illustrates the dramatic variation in wholesale spot energy prices in PJM from day to day during 2010 and, for two selected days, from hour to hour.</p>
<p>Many large commercial and industrial customers already operate under dynamic pricing. Such pricing regimes likely will also be widespread options—if not the default—for residential consumers by 2030, with third parties generally enabled to provide equipment to automate response to price changes. However, response automation technologies aren’t yet mature, in part because further research on the behavior of residential consumers faced with dynamic pricing is needed, and residential dynamic pricing requires substantial investment in advanced metering infrastructure (AMI) to measure usage over short time intervals. Substantial AMI investments have recently been funded through the <i>American Recovery and Reinvestment Act </i>(ARRA) of 2009, and some state regulators have mandated universal AMI deployment. But there has been little if any movement toward the dynamic pricing regimes that AMI enables. Given the enormous potential value of dynamic pricing of electricity, regulators and utilities should exploit the important learning opportunities the ARRA-supported and regulator-mandated investments in AMI have provided to develop efficient paths to universal dynamic pricing—and then to follow those paths.</p>
<p>On the other hand, utilities that haven’t committed to AMI systems, and for which the operational benefits of these systems are less than their cost, should take advantage of the option to learn from early adopters before making a decision to invest. Among other things, further research is needed on consumer reactions to dynamic pricing, and effective consumer engagement and education strategies must be designed and tested in the field. To facilitate this, it’s important that detailed information on the results of early AMI deployments be made promptly and widely available. Finally, where wholesale electricity markets exist, effective competition in the retail sales of electricity might stimulate innovation in ways to make dynamic pricing both acceptable to consumers—and regulators—and effective in modifying demand.</p>
<h4>Distributed Generation</h4>
<p>Existing policies at state and federal levels favor distributed generation, particularly small-scale wind and solar, and these policies seem likely to continue. In addition to subsidies and regulatory mandates, 46 states and the District of Columbia have net-metering programs, which pay distributed generators for electricity they deliver to the grid at the retail rate rather than the wholesale rate that central station generators receive. The difference is mainly the cost of distribution—and sometimes transmission—which is almost entirely fixed in the short run but is typically recovered through per-kWh charges. Thus a customer who generates electricity onsite saves both the energy charge and the distribution charge for that electricity, but the utility saves only the corresponding energy cost. In this way, recovering network costs through per-kWh charges provides an additional subsidy to distributed generation of all sorts—both clean solar and dirty diesel—that might encourage its uneconomic penetration. Perhaps more importantly, this regime gives utilities disincentives to accommodate distributed generation or encourage energy efficiency, since both reduce its sales and profits.</p>
<p>The necessary policy change is straightforward but important. Fixed network costs should be recovered primarily through fixed customer charges. These charges might differ among customers, but shouldn’t vary with kWh consumption. For example, customer groups that are expected to contribute more to local peak demand based on their pattern of prior consumption could pay a higher fixed charge than customer groups that are expected to contribute less. Systems that continue to rely significantly on per-kWh charges for cost recovery should improve utility incentives by decoupling utility revenues from short-run changes in sales.</p>
<p>At high levels of penetration, distributed generation can exceed load at the substation level, causing unusual distribution flow patterns. These can produce high voltage swings, which can be detrimental to customer equipment. High levels of penetration can also add to the stress on electrical equipment, such as circuit breakers, and complicate the ability to operate the distribution system, particularly during emergencies and planned outages. Additional monitoring and new standards for operation, protection, and control will be necessary to enable significant penetration of distributed generation.</p>
<h4>Reliability and Efficiency</h4>
<p>New technologies can improve operator knowledge about the state of the transmission system and thus make possible more efficient and reliable operation. Phasor measurement units (PMUs) are powerful devices, being widely deployed with ARRA support, that provide rich streams of frequent, time-stamped data on system conditions that system operators can use to anticipate contingencies, reduce the risk of wide-area blackouts, enhance system efficiency and improve system models. In addition, flexible alternating current transmission system (FACTS) devices based on advances in power electronics can provide greater control of voltages and power flows throughout the bulk power system. FACTS and other new technologies can allow more power to be transmitted on existing lines without increasing the risk of failure, but historically the incremental benefits haven’t justified the associated costs in most cases. Higher penetration of VERs likely will increase the value of deploying these technologies in the transmission system.</p>
<p>Research on the new algorithms, software, and communication systems required to integrate PMUs and FACTS devices effectively into system operations is likely to have a particularly high payoff. If shared, data generated by existing PMUs can be used to develop algorithms and establish baselines for future operational tools that can monitor and control networks with greater PMU and FACTS penetration.</p>
<p>Many technologies are available to enhance the reliability and efficiency of distribution systems, but—in part because it’s often more cost-effective to invest in monitoring and control systems at the transmission level than the distribution level—many available technologies haven’t yet been widely implemented at the distribution level in the U.S. However, coping efficiently with the integration of distributed generation, electric vehicles, and demand response will require significant investments in new and emerging technologies that will be riskier than most recent investments in distribution systems; they will aim to provide new capabilities, not just expand capacity. The tendency of traditional regulatory systems to encourage excessively conservative behavior likely will become more and more expensive over time if increasingly attractive opportunities to enhance efficiency and reduce cost through the deployment of unfamiliar technology aren’t exploited. This is an important problem—but one without an obvious solution, since both regulators and utilities seem to be punished for bad outcomes but not rewarded for good ones. Nonetheless, regulatory innovations are necessary to provide adequate incentives for investments in unfamiliar technologies while also ensuring that the returns on these investments are shared appropriately with ratepayers. To reduce perceived uncertainties and make possible better system-specific decisions, it’s important that detailed information on the results of the DOE-supported smart grid projects and other pilot projects, both successes and failures, be shared promptly and widely.</p>
<h4>Cybersecurity and Privacy</h4>
<p>The historical evolution of today’s electric grid, through the interconnection of small, local power systems, enhanced reliability overall but made possible wide-area blackouts. Similarly, the increasing use of new communications systems, sensing and control equipment, AMI, and distribution automation technologies will enhance reliability and efficiency overall but also will create new problems.</p>
<p>Over the next two decades, increasing amounts of data will be exchanged within the electric power system through a complex set of communications systems that must follow standards that allow various components to interoperate now and in the future, when later generations of equipment are installed. The National Institute of Standards and Technology (NIST) is overseeing the critical process of developing the relevant interoperability standards, and this process should be encouraged and supported. In addition, there are ongoing debates about the use of spectrum and the roles of public and private networks. Resolution of the former debate rests with the FCC, while opportunities for both public and private networks likely will exist unless the regulatory environment treats them unequally.</p>
<p>As Figure 4 indicates, cybersecurity involves more than protecting against attacks. In fact, as communications systems expand into every facet of grid control and operations, their complexity and continuous evolution will preclude perfect protection from cyber attacks. Response and recovery, in addition to preparedness, will thus be important components of cybersecurity, and it’s important for the involved government agencies, working with the private sector and publicly owned utilities in a coordinated fashion, to support the research necessary to develop best practices for response to and recovery from cyber attacks on transmission and distribution systems, and to deploy those practices rapidly and widely.</p>
<p>NERC is responsible for cybersecurity standards development and compliance for the bulk power system, but no entity has comparable nationwide responsibility for distribution systems. State PUCs—which generally are responsible only for investor-owned distribution systems— generally lack cybersecurity expertise, and the same is true of municipal utilities, cooperatives, and other public systems. While the consequences of a successful attack on the bulk power system are potentially much greater than an attack at the distribution level, the boundary between transmission and distribution has become increasingly blurred, and distribution level cybersecurity risks deserve serious attention. NIST is facilitating the development of cybersecurity standards broadly, but it doesn’t have an operational role. Thus no agency currently has responsibility for cybersecurity across all aspects of grid operations.</p>
<p>This is a serious problem, and we strongly recommend that a single federal agency be clearly given responsibility for working with industry as well as appropriate regulatory authority to enhance cybersecurity preparedness, response, and recovery across the electric power sector, including both bulk power and distribution systems. This might require new legislation, and legislative proposals designating either a combination of FERC and DOE or the Department of Homeland Security (DHS) have recently been advanced. Once a lead agency has been designated, it should take all necessary steps to ensure that it has appropriate expertise by working with NERC and other relevant federal agencies, as well as state PUCs, public power authorities, and such expert organizations as IEEE and EPRI.</p>
<p>With the collection, transmission, processing, and storage of increasing amounts of information on customer electricity usage also comes heightened concern for protecting the privacy of that information. Deciding who has access rights to these personal data and ensuring consumers’ privacy will be important considerations in the design and operation of grid communications networks. The complex issues involved are being actively debated in several states. Coordination across states will be necessary to mitigate concerns of companies that operate in multiple jurisdictions, and the concerns of their customers, as data on both companies and their customers regularly cross state boundaries.</p>
<h4>Challenges Ahead</h4>
<p>Despite alarmist rhetoric, the U.S. electric grid is not in crisis, but complacency would be unwise. Significant opportunities and challenges loom, and between now and 2030 the grid will inevitably undergo major changes. If the grid is to evolve along an efficient path with minimal disruption despite the challenges ahead, and if electricity rates and levels of reliability are to remain acceptable, various system-level issues need to be addressed, and new technologies need to be used as appropriate. Regulators need to change their policies in significant ways to better align incentives of participants in electricity markets—including consumers—with policy goals. Important data need to be collected and shared appropriately to improve decision-making.</p>
<p>Research in several key areas also will be required. The electric utility industry traditionally has relied primarily on its suppliers for the innovation that has driven its productivity growth. Supplier R&amp;D naturally has focused on equipment that can be sold to utilities. Additional modest but sustained efforts in several non-equipment related research areas mentioned above are likely to have substantial payoffs, and these are unlikely to attract equipment vendors. The electric utility industry itself should be able to support the efforts required, however, even if federal support doesn’t materialize. For this to happen, regulators will need to recognize that technical progress benefits consumers broadly, and permit modest increases in utility R&amp;D budgets. It also will likely be necessary for the industry to reverse the downward trend in cooperative R&amp;D spending and make appropriate use of cooperative funding through EPRI, one or more independent system operators, and project-specific coalitions.</p>
<p>The journey to the electric grid of 2030 has begun, and there will be plenty of surprises along the way. Much can and should be done now to smooth the potentially very bumpy road ahead.</p>
<p> </p>
<h4>Endnotes:</h4>
<p>1. <a href="http://abcnews.go.com/US/story?id=90321&amp;page=1" target="_blank">http://abcnews.go.com/US/story?id=90321&amp;page=1</a></p>
<p>2. U.S. Department of Energy, <i>The Smart Grid: An Introduction</i>, p.2, U.S. Department of Energy, Washington, D.C.</p>
<p>3. MIT Energy Initiative, <a href="http://web.mit.edu/mitei/research/energy-studies.html" target="_blank">The Future of the Electric Grid</a>, MIT Energy Initiative, 2011, Cambridge, Mass.</p>
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<a href="/tags/american-recovery-and-reinvestment-act">American Recovery and Reinvestment Act</a><span class="pur_comma">, </span><a href="/tags/ami">AMI</a><span class="pur_comma">, </span><a href="/tags/ami-deployments">AMI deployments</a><span class="pur_comma">, </span><a href="/tags/arra">ARRA</a><span class="pur_comma">, </span><a href="/tags/cost-allocation">cost allocation</a><span class="pur_comma">, </span><a href="/tags/department-energy">Department of Energy</a><span class="pur_comma">, </span><a href="/tags/department-homeland-security">Department of Homeland Security</a><span class="pur_comma">, </span><a href="/tags/dhs">DHS</a><span class="pur_comma">, </span><a href="/tags/doe">DOE</a><span class="pur_comma">, </span><a href="/tags/energy-policy-act">Energy Policy Act</a><span class="pur_comma">, </span><a href="/tags/epri">EPRI</a><span class="pur_comma">, </span><a href="/tags/ev">EV</a><span class="pur_comma">, </span><a href="/tags/evs">EVs</a><span class="pur_comma">, </span><a href="/tags/facts">FACTS</a><span class="pur_comma">, </span><a href="/tags/fcc">FCC</a><span class="pur_comma">, </span><a href="/tags/ferc">FERC</a><span class="pur_comma">, </span><a href="/tags/iee">IEE</a><span class="pur_comma">, </span><a href="/tags/ieee">IEEE</a><span class="pur_comma">, </span><a href="/tags/interoperability-standards">interoperability standards</a><span class="pur_comma">, </span><a href="/tags/it">IT</a><span class="pur_comma">, </span><a href="/tags/mit">MIT</a><span class="pur_comma">, </span><a href="/tags/national-institute-standards-and-technology">National Institute of Standards and Technology</a><span class="pur_comma">, </span><a href="/tags/nerc">NERC</a><span class="pur_comma">, </span><a href="/tags/new-technologies">New technologies</a><span class="pur_comma">, </span><a href="/tags/nist">NIST</a><span class="pur_comma">, </span><a href="/tags/order-no-1000">Order No. 1000</a><span class="pur_comma">, </span><a href="/tags/phasor-measurement-units">Phasor measurement units</a><span class="pur_comma">, </span><a href="/tags/pjm">PJM</a><span class="pur_comma">, </span><a href="/tags/pmu">PMU</a><span class="pur_comma">, </span><a href="/tags/privacy">Privacy</a><span class="pur_comma">, </span><a href="/tags/recovery">Recovery</a><span class="pur_comma">, </span><a href="/tags/reliability">Reliability</a><span class="pur_comma">, </span><a href="/tags/security">Security</a><span class="pur_comma">, </span><a href="/tags/storage">storage</a><span class="pur_comma">, </span><a href="/tags/technology">Technology</a><span class="pur_comma">, </span><a href="/tags/transmission">Transmission</a><span class="pur_comma">, </span><a href="/tags/transmission-and-distribution">Transmission and distribution</a><span class="pur_comma">, </span><a href="/tags/us-department-energy">U.S. Department of Energy</a><span class="pur_comma">, </span><a href="/tags/variable">Variable</a><span class="pur_comma">, </span><a href="/tags/ver">VER</a> </div>
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Sun, 01 Jan 2012 05:00:00 +0000puradmin13433 at http://www.fortnightly.comTres Amigas Tie Uphttp://www.fortnightly.com/fortnightly/2010/07/tres-amigas-tie
<div class="field field-name-field-import-deck field-type-text-long field-label-inline clearfix"><div class="field-label">Deck:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Synchronizing networks to bring green power to market.</p>
</div></div></div><div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Jeremiah D. Lambert</p>
</div></div></div><div class="field field-name-field-import-category field-type-text field-label-inline clearfix"><div class="field-label">Category:&nbsp;</div><div class="field-items"><div class="field-item even">Technology Corridor</div></div></div><div class="field field-name-field-import-bio field-type-text-long field-label-inline clearfix"><div class="field-label">Author Bio:&nbsp;</div><div class="field-items"><div class="field-item even"><p><b>Mr. Lambert</b> practices law in Washington, D.C., and serves as general counsel for Tres Amigas, LLC. Email him at <a href="mailto:jlambert@lambertlaw.net">jlambert@lambertlaw.net</a></p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - July 2010</div></div></div><div class="field field-name-field-import-image field-type-image field-label-above"><div class="field-label">Image:&nbsp;</div><div class="field-items"><div class="field-item even"><img src="http://www.fortnightly.com/sites/default/files/article_images/1007/images/1007-TC-fig1.jpg" width="1360" height="1294" alt="" /></div><div class="field-item odd"><img src="http://www.fortnightly.com/sites/default/files/article_images/1007/images/1007-TC-fig2.jpg" width="1366" height="948" alt="" /></div><div class="field-item even"><img src="http://www.fortnightly.com/sites/default/files/article_images/1007/images/1007-TC-fig3.jpg" width="1368" height="924" alt="" /></div><div class="field-item odd"><img src="http://www.fortnightly.com/sites/default/files/article_images/1007/images/1007-TC-fig4.jpg" width="2064" height="920" alt="" /></div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p>In 2008, testifying before the Senate Energy and Natural Resources Committee, T. Boone Pickens appeared as a persuasive, if unlikely, advocate for wind energy. He told the committee his company, Mesa Power, had just placed the largest single turbine order ever given and the Mesa Pampa Wind Project in Texas, when completed at a cost close to $10 billion, would generate 4,000 MW—enough energy to power 1.3 million homes. He also noted a potential pitfall: “[T]he large, flat open areas with adequate wind are usually located a long way from where electricity is needed. Since we can’t do much about where nature has put the wind, we have to do something about transmission to move electricity to market.”</p>
<p>Less than two years later, Pickens abandoned his project, saying he would build a wind farm in the Panhandle when transmission is built. Pickens’ change of fortune illustrates a problem. The United States is home to vast clean energy resources, but lacks a modern interstate transmission grid to deliver carbon-free electricity to customers in highly populated areas. Almost 300 GW of wind projects—output that potentially could meet 20 percent of the nation’s energy needs—now are waiting in line to connect to the grid because there isn’t enough transmission capacity to carry their power.</p>
<p>But transmission lines are only part of the solution. In order to fully integrate wind and other dispersed sources of energy into the system, America’s patchwork transmission networks need to be more closely interconnected and synchronized. That’s the goal of the proposed Tres Amigas merchant transmission project.</p>
<p><b>Grid Balkanization </b></p>
<p>Many industry studies have identified systemic problems, principal among them division of the nation’s transmission grid into three asynchronous alternating current (AC) networks with little existing transmission transfer capacity between them: the Eastern Interconnection (EI, also referred to as SPP), Western Interconnection (WECC), and Electric Reliability Council of Texas (ERCOT). Power sourced in one region can’t presently be delivered in another even if the price that would be paid in the latter is higher than that in the former (<i>see Figures 2 and 3</i>). This balkanization is a major barrier to renewable energy development.</p>
<p>High-voltage direct-current (HVDC) transmission technology provides a feasible way to interconnect asynchronous power grids and allow presently bottlenecked renewable power to reach load centers. Using voltage source converters (VSCs) to transform alternating current (AC) to direct current (DC) and then reconstitute it as synchronized AC, this technology can deliver active and reactive power independently, unaffected by loop flow or the congestion of parallel AC systems. VSCs permit real-time dynamic support of each interconnected AC system, improving stability, transfer capability, and reducing line losses. Fully controllable HVDC power transmission permits day-ahead and hour-ahead market scheduling, operation of inter-market power exchanges, and priced settlement of power transfers.</p>
<p>Recognizing a unique opportunity, Tres Amigas, LLC, a privately financed start-up company organized by Phil Harris, the former chief executive officer of PJM, has launched a merchant transmission project to be located on a 14,000 acre site near Clovis, N.M. The project will be a superstation hub using DC to link asynchronous power markets in the EI, WECC, and ERCOT, regulate the direction and level of power flows between them, and make possible efficient energy transactions now precluded by each market’s inaccessibility to the others.</p>
<p>The project would permit power sellers in ERCOT to schedule power to either the EI or WECC; power sellers in the EI to schedule power to ERCOT or the WECC; and power sellers in the WECC to schedule power to either ERCOT or the EI, thereby providing expanded markets for renewable and other sources of power. The project also would form a balancing authority within WECC and support planned HVDC transmission overlay projects nationwide.</p>
<p>As envisaged, the Tres Amigas project initially will have three energy conversion terminals, each with a 750-MW VSC employing insulated-gate bipolar transistors (IGBT), to provide 5 GW of capacity, scalable over time to 30 GW to accommodate additional demand. IGBT technology enables the VSC to change the AC wave form into a DC circuit with conventional voltage and current characteristics and then, with precise control, to change it back to an AC wave form. The terminals would be linked by several miles of underground liquid nitrogen-cooled cable manufactured by American Superconductor, enabling high power flows with low resistance. The project also includes up to 100 MW of battery storage to provide ancillary services and reactive power to firm intermittent renewable resources. An optimization engine will determine generation and transmission utilization, congestion, reliability indices, and variable market conditions.</p>
<p>The project is a merchant facility and won’t have captive customers or rely on regulated cost-based rates. Project sponsors will bear all risks. To succeed commercially, the project will have to generate income by selling transmission rights, ancillary services, and reactive power to customers that see advantages in extending to the project interconnecting transmission lines, such as AEP-MidAmerican, Southwest Public Service, Sharyland Utilities, Xcel Energy, and Public Service Co. of New Mexico. Project income will be a function of the margin created by differing power prices in the EI, WECC, and ERCOT, a fraction of which will be captured as transmission revenue through sale of long-term and spot transmission rights. The resulting dollars must be sufficient to permit the leveraged financing of a capital-intensive facility costing north of $500 million.</p>
<p><b>Negotiated Rates </b></p>
<p>To obtain required regulatory approvals, last December Tres Amigas filed two parallel applications at the Federal Energy Regulatory Commission (FERC), one seeking authorization to sell transmission rights at negotiated rates and the other seeking a disclaimer of federal jurisdiction over any transmission owner that constructs transmission facilities interconnecting the ERCOT grid to the project.</p>
<p>In its negotiated rates application, Tres Amigas proposed to offer for bilateral sale, point-to-point physical transmission rights based on firm transfer capability from one scheduling point to either of the other two scheduling points. Thus, for an ERCOT seller, firm transmission rights would be framed by the ability to schedule power from the ERCOT terminal to one of the other two terminals at the EI or WECC interconnections. Transmission rights therefore would entail firm point-to-point service from one delivery point to one receipt point, but also would include the right to redirect schedules to an alternative delivery or receipt point on a firm or non-firm basis as permitted under FERC’s <i>pro forma</i> open access transmission tariff (OATT) and the right to resell transmission rights in the secondary market.</p>
<p>The application contemplated successive open season auctions of transmission rights in time blocks of different duration representing up to 80 percent of the project’s initial capacity before commercial start-up, the amount of capacity offered and the applicable time blocks to be based on Tres Amigas’ contemporaneous assessment of the market. Transmission rights would be sold on a non-discriminatory basis to the highest creditworthy bidder. The application also proposed that Tres Amigas would retain the right to reserve up to 20 percent of the capacity at each terminal for sale in open season auctions after the project commences commercial operation, by which time all available capacity at each of the scheduling points would have been made available for sale bilaterally, in open season auctions, or under the OATT.</p>
<p>Citing a recent FERC order as precedent, the application also took note of Tres Amigas’ probable need to support early development efforts by selling transmission rights representing up to 50 percent of the capacity of the project at each scheduling terminal to anchor customers under bilaterally negotiated agreements. In doing so, the application argued that the rates to be charged, being competitively determined, would be just and reasonable and that capacity would not be withheld as a means of raising prices.</p>
<p>This March, FERC granted Tres Amigas’ application, subject to certain limitations. It accepted allocation of 50 percent of initial capacity to anchor customers, but denied Tres Amigas’ request to hold back 20 percent of initial capacity for discretionary sale. It also required that, before entering into an anchor customer agreement, Tres Amigas first must obtain FERC’s authorization; be prepared to offer the same terms to open season customers; and refrain from withholding capacity that isn’t committed to anchor customers during the open season process, either through creation of tranches of capacity or by offering less than the full amount of available capacity in any auction. As a practical matter, Tres Amigas must declare the amount of initial capacity it will offer at the outset of the open season process and allocate later capacity additions or availability, if any, under the OATT.</p>
<p>FERC found that “sufficient long-term checks are in place to ensure that negotiated rates for transmission service … will be just and reasonable,” including competition from capacity owners’ secondary transmission rights, options to purchase capacity on existing AC/DC interties, differences in the price of generation in the relevant markets, and Tres Amigas’ commitment to expand the project at cost-of-service rates if expansion pursuant to negotiated rates isn’t feasible. “With no captive pool of customers from which [Tres Amigas] can recover its cost,” FERC concluded, “the only way in which it will attract customers is to provide a service that has some economic value to market participants. If [it] does not offer some benefit to prospective customers, it will not be able to recover the investment for which it has assumed the risk.”</p>
<p><b>Disclaimer of Jurisdiction </b></p>
<p>Although opportunities exist to build transmission lines from competitive renewable energy zones (CREZ) in Texas interconnecting with the project, ERCOT utilities advised Tres Amigas they wouldn’t be able to obtain approvals in Texas to construct such lines absent a FERC disclaimer of jurisdiction—necessary, they asserted, to preserve ERCOT’s plenary exemption from federal oversight.</p>
<p>Accordingly, Tres Amigas filed an application at FERC requesting a three-part ruling that any transmission owner whose lines interconnect the ERCOT grid to the project won’t be subject to FERC jurisdiction as a public utility under federal law; transmission services over AC lines from ERCOT to the project (<i>i.e.</i>, synchronized with the ERCOT grid) won’t be subject to FERC jurisdiction; and creation of a new AC to DC interconnection between the project and ERCOT won’t change the existing jurisdictional status of any ERCOT utilities or transactions.</p>
<p>The application advanced alternative legal bases for relief, the first an omnibus rationale that the AC electric grid in ERCOT, which isn’t synchronized with out-of-state systems, doesn’t allow locally sourced energy to “commingle” in interstate commerce and therefore isn’t subject to FERC jurisdiction. The second argument urged FERC to rule that Tres Amigas would be eligible for jurisdictional disclaimer under Section 201(b)(2) the <i>Federal Power Act </i>(FPA) if it were to obtain a wheeling order under Section 211. The third argument justified a jurisdictional disclaimer based on “the unique design of the Tres Amigas superstation, which will maintain the electrical separation of ERCOT and the interstate grids using new technology and a unique configuration of facilities.”</p>
<p>The FPA confers FERC jurisdiction over all transmission facilities that operate in interstate commerce but expressly recognizes ERCOT as a separate jurisdictional entity outside interstate commerce, regulated by the Public Utility Commission of Texas. Whether transmission lines and energy transactions are deemed to be, or take place in, interstate commerce depends, according to Supreme Court precedent, on a factual determination that electricity within a synchronized AC grid “commingles” across state lines. Tres Amigas argued that “commingling” doesn’t apply to electricity flows between asynchronous grids, such as ERCOT and the EI or WECC, linked by AC/DC converters. When so linked, for power to be scheduled from one interconnection to another, the current first must be converted from an AC wave to a DC pulse and then back to an AC wave synchronized with the receiving grid. As a result, the power isn’t free-flowing or commingled; arguably isn’t in interstate commerce; and therefore doesn’t subject transmission lines within ERCOT or the transaction itself to federal jurisdiction.</p>
<p>Tres Amigas’ second argument invoked FERC’s power, under the <i>Public Utility Regulatory Policies Act </i>of 1978, to order interconnection (FPA<i>, Section 210</i>) and wheeling (FPA<i>, Section 211</i>) by a non-jurisdictional entity without subjecting it to FERC regulation. By filing a voluntary application for interconnection under Section 210 or a wheeling order under Section 211, the parties to a proposed transaction may in principle take advantage of Section 201(b)(2) of the FPA, which states that “compliance with any order of the commission under the provisions of section 210 or 211 shall not make an electric utility or other entity subject to the jurisdiction of the Commission…” Tres Amigas noted, however, that an entity building transmission lines to interconnect the ERCOT grid with the project can’t be an electric utility, <i>i.e.</i>, a “person. . . that sells electricity” as defined by the FPA, because, under Texas statutory law, “a transmission and distribution utility may not sell electricity…” Accordingly, it conceded, an order under Section 210 wouldn’t be obtainable.</p>
<p>Tres Amigas’ second argument therefore turned on Section 211, under which FERC would disclaim jurisdiction if and when Tres Amigas, itself an electric utility because of energy to be supplied from battery storage, obtained an order under that section directing the ERCOT interconnecting party, a transmitting utility, to wheel power to the project. Under the FPA a “transmitting utility” is an entity that owns or operates transmission facilities in interstate commerce and transmits power at wholesale. FERC therefore would have to find that, but for the jurisdictional exemption provided by Section 211, the ERCOT interconnecting entity would be operating transmission facilities in interstate commerce upon interconnection with the project.</p>
<p>To implement a disclaimer of jurisdiction under Section 211, Tres Amigas agreed to apply for a FERC order directing ERCOT transmitting utilities to wheel power over proposed transmission lines to the project. It also sought FERC’s confirmation that it would be entitled to receive a favorable Section 211 order upon demonstrating that the ordered wheeling will be “in the public interest,” won’t “unreasonably impair the continued reliability of electric systems affected by such order,” and will satisfy federal requirements concerning rates and terms and conditions of ordered transmission service.</p>
<p>Tres Amigas’ third argument urged FERC to disclaim jurisdiction because, among other circumstances, all the electric power flowing over interconnecting lines owned by the ERCOT transmission owner will be synchronized solely with the ERCOT grid and any power sourced in the WECC or EI will be converted by the project to ERCOT-synchronized AC current before entering the ERCOT lines. Tres Amigas also noted that the project would act as a balancing authority operating its own DC system, with several miles of DC transmission lines interposed between the ERCOT interconnection and the WECC and EI grids. Finally, Tres Amigas contended that the real and reactive DC power produced by the project’s VSCs would be fully controllable in contrast to uncontrolled power flows on an AC grid. For the foregoing reasons, Tres Amigas contended, electricity flowing in ERCOT interconnecting transmission lines won’t be commingled with electricity in FERC-jurisdictional grids.</p>
<p>In a parallel order this March, FERC denied Tres Amigas’ application for a disclaimer of jurisdiction. “Independent of whether ‘commingling’ occurs at the Project,” it said, “power transmitted to and from the Project crosses the Texas/New Mexico border. Without the benefit of an exemption under the FPA, … the interconnection proposed would result in ERCOT and ERCOT utilities becoming subject to the Commission’s jurisdiction as public utilities.” FERC also declined to issue a blanket section 211 order without knowing the specific parties and circumstances, but said, upon receiving an application consistent with the requirements of section 211, it might issue an exemptive order to allow “interconnection and transmission of energy between ERCOT and the Project while retaining the jurisdictional status quo.”</p>
<p><b>Project Economics </b></p>
<p>Following issuance of the FERC orders, Tres Amigas has focused on the practical economics of project development and revenue generation. The task at hand is broadly summarized by Paul Joskow of MIT in his 2003 white paper on merchant transmission investment, co-authored with Jean Tirole. “In return for investment in additional transmission capacity,” he writes, “merchant investors receive property rights that allow them to collect congestion revenues equal to the difference in nodal energy prices associated with the incremental point-to-point transmission capacity their investments create. The value of those rights to relieve congestion revenues represents the revenues merchant investors receive to cover the capital and operating costs of their investments.”</p>
<p>The project’s revenue potential is a function in part of congestion rents, <i>i.e.</i>, the prices, less transmission charges, a buyer would need to pay to interconnecting utilities to complete a trade using Tres Amigas’ project facilities. Congestion rents are expressed as the difference between energy prices at the source and sink. Based on historical data, total annual congestion rents can be calculated as the aggregate of constituent congestion rents across each of six paths (<i>e.g.</i>, WECC to SPP, SPP to WECC, <i>etc.</i>). This difference in locational prices is seen as the predicate for customers’ willingness to buy transmission rights and committing to use the project’s transmission capacity in the longer term (<i>see Figure 4</i>). Beyond average regional price differences, market-price volatility is expected to permit arbitrage to capture additional revenue based on operational flexibility and dispatch. These factors will shape Tres Amigas’ bilateral negotiations with anchor customers and open-season auction strategy.</p>
<p>At this writing, Tres Amigas is still in the early stages of mounting a complex, long-term, capital-intensive project that isn’t expected to come on-stream until 2014. Definitive financing arrangements aren’t yet in place; agreements with anchor customers and interconnecting utilities remain to be negotiated; and procurement of high-tech customized equipment has just begun.</p>
<p>Nonetheless, the project has a reasonable chance of proceeding because it would reinforce transmission initiatives underway in WECC (High Plains Express, New Mexico Wind Collector, and SunZia), ERCOT (CREZ), and EI (SPP EHV Overlay). If it succeeds, Tres Amigas is expected to enhance reliability of the national grid and promote the national corridor transmission system.</p>
</div></div></div><div class="field field-name-field-article-category field-type-taxonomy-term-reference field-label-above clearfix"><h3 class="field-label">Category (Actual): </h3><ul class="links"><li class="taxonomy-term-reference-0"><a href="/article-categories/td-grid">T&amp;D Grid</a></li><li class="taxonomy-term-reference-1"><a href="/article-categories/transmission">Transmission</a></li></ul></div><div class="field field-name-field-members-only field-type-list-boolean field-label-above"><div class="field-label">Viewable to All?:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-article-featured field-type-list-boolean field-label-above"><div class="field-label">Is Featured?:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-department field-type-taxonomy-term-reference field-label-above clearfix"><h3 class="field-label">Department: </h3><ul class="links"><li class="taxonomy-term-reference-0"><a href="/department/technology-corridor">Technology Corridor</a></li></ul></div><div class="field field-name-field-image-picture field-type-image field-label-above"><div class="field-label">Image Picture:&nbsp;</div><div class="field-items"><div class="field-item even"><img src="http://www.fortnightly.com/sites/default/files/article_images/1007/images/1007-cvr.jpg" width="1121" height="1500" alt="" /></div></div></div><div class="field field-name-field-fortnightly-40 field-type-list-boolean field-label-above"><div class="field-label">Is Fortnightly 40?:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-law-lawyers field-type-list-boolean field-label-above"><div class="field-label">Is Law &amp; Lawyers:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-tags field-type-taxonomy-term-reference field-label-above clearfix">
<div class="field-label">Tags:&nbsp;</div>
<div class="field-items">
<a href="/tags/aep">AEP</a><span class="pur_comma">, </span><a href="/tags/american-superconductor">American Superconductor</a><span class="pur_comma">, </span><a href="/tags/citi">Citi</a><span class="pur_comma">, </span><a href="/tags/commission">Commission</a><span class="pur_comma">, </span><a href="/tags/crez">CREZ</a><span class="pur_comma">, </span><a href="/tags/dc">DC</a><span class="pur_comma">, </span><a href="/tags/eastern-interconnection">Eastern Interconnection</a><span class="pur_comma">, </span><a href="/tags/economics">Economics</a><span class="pur_comma">, </span><a href="/tags/ehv">EHV</a><span class="pur_comma">, </span><a href="/tags/electric-reliability-council-texas">Electric Reliability Council of Texas</a><span class="pur_comma">, </span><a href="/tags/electric-reliability-council-texas-ercot">Electric Reliability Council of Texas (ERCOT)</a><span class="pur_comma">, </span><a href="/tags/energy-and-natural-resources-committee">Energy and Natural Resources Committee</a><span class="pur_comma">, </span><a href="/tags/ercot">ERCOT</a><span class="pur_comma">, </span><a href="/tags/federal-energy-regulatory-commission">Federal Energy Regulatory Commission</a><span class="pur_comma">, </span><a href="/tags/federal-energy-regulatory-commission-ferc">Federal Energy Regulatory Commission (FERC)</a><span class="pur_comma">, </span><a href="/tags/federal-power-act">Federal Power Act</a><span class="pur_comma">, </span><a href="/tags/ferc">FERC</a><span class="pur_comma">, </span><a href="/tags/fpa">FPA</a><span class="pur_comma">, </span><a href="/tags/gbt">GBT</a><span class="pur_comma">, </span><a href="/tags/hvdc">HVDC</a><span class="pur_comma">, </span><a href="/tags/interconnection">Interconnection</a><span class="pur_comma">, </span><a href="/tags/it">IT</a><span class="pur_comma">, </span><a href="/tags/midamerican">MidAmerican</a><span class="pur_comma">, </span><a href="/tags/mit">MIT</a><span class="pur_comma">, </span><a href="/tags/oatt">OATT</a><span class="pur_comma">, </span><a href="/tags/ot">OT</a><span class="pur_comma">, </span><a href="/tags/paul-joskow">Paul Joskow</a><span class="pur_comma">, </span><a href="/tags/pjm">PJM</a><span class="pur_comma">, </span><a href="/tags/public-utility-commission-texas">Public Utility Commission of Texas</a><span class="pur_comma">, </span><a href="/tags/public-utility-regulatory-policies-act">Public Utility Regulatory Policies Act</a><span class="pur_comma">, </span><a href="/tags/reliability">Reliability</a><span class="pur_comma">, </span><a href="/tags/spp">SPP</a><span class="pur_comma">, </span><a href="/tags/storage">storage</a><span class="pur_comma">, </span><a href="/tags/sunzia">SunZia</a><span class="pur_comma">, </span><a href="/tags/transmission">Transmission</a><span class="pur_comma">, </span><a href="/tags/tres-amigas">Tres Amigas</a><span class="pur_comma">, </span><a href="/tags/wecc">WECC</a><span class="pur_comma">, </span><a href="/tags/wind">Wind</a><span class="pur_comma">, </span><a href="/tags/xcel-energy">Xcel Energy</a> </div>
</div>
Thu, 01 Jul 2010 04:00:00 +0000puradmin13618 at http://www.fortnightly.comBlue Ribbon Missionhttp://www.fortnightly.com/fortnightly/2010/07/blue-ribbon-mission
<div class="field field-name-field-import-deck field-type-text-long field-label-inline clearfix"><div class="field-label">Deck:&nbsp;</div><div class="field-items"><div class="field-item even"><p><b>Can a broadly based committee resolve the nuclear waste dilemma? </b></p>
</div></div></div><div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>John Bewick</p>
</div></div></div><div class="field field-name-field-import-bio field-type-text-long field-label-inline clearfix"><div class="field-label">Author Bio:&nbsp;</div><div class="field-items"><div class="field-item even"><p><b>John Bewick</b> is a former secretary of environmental affairs for the Commonwealth of Massachusetts, and director, verification and validation services, with Enviroplan Consulting. A frequent contributor to Public Utilities Fortnightly, Bewick, who holds a graduate degree in nuclear science, is covering the nuclear Blue Ribbon Commission’s work on an ongoing basis for <i>Fortnightly</i> and <i>Fortnightly.com</i>.</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - July 2010</div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p>In January, the Obama administration appointed a high-powered Blue Ribbon Commission on America’s Nuclear Future (BRC) to address one of the nation’s great continuing dilemmas, the management and disposition of nuclear waste.</p>
<p>Delivering his charge to commission members at their organizational meeting, Energy Secretary Stephen Chu set forth their challenge, and gave the commission a two-year time frame to work with. The commission isn’t tasked to site a repository, but rather to look at the whole nuclear fuel cycle, and at what technologies might be available in coming years that will affect that cycle. He wants commission members to review how things should be set up as technology progresses, both to reduce the amount of or the toxicity of the material separated from spent fuel, and to determine how to dispose of what won’t be wanted, the residual material, in the future, both near term and long term. He also asked the BRC to recommend changes to the decision process.</p>
<p>Among other guideposts for the commission, Secretary Chu pointed out that the NRC has made clear that dry-cask storage above ground is safe for decades—possibly 100 years. However, he also suggested the commission needs to deal with the problems that might emerge after those decades elapse, including the possibility of high-burnup reactors that might reduce the lifetime of the waste and change what’s needed for disposal in the future.</p>
<p>Given this broad set of marching orders, cynics might argue that the BRC provides nothing more than political cover for the Obama administration—to lend credence to its stated support for zero-carbon emitting nuclear development, and to show that it’s working on an alternative to the Yucca Mountain repository that it took “off the table” last year. But at their first meeting earlier this year, the BRC commissioners themselves expressed determination to avoid becoming just another Washington committee providing a report for the National Archives. As evidence of their intent, the second session in late May provided an excellent seminar on the range of complex issues BRC members must weigh in their deliberations.</p>
<p>The composition of the commission itself is reassuring. One Washington nuclear scientist observed (under condition of anonymity) that with the makeup of the commission’s membership, it must be taken seriously. Appointed members include knowledgeable members, capable of crafting both a sensible technical road map for the future as well as one that will be politically credible. Those with respected political credentials include former Congressmen like Phil Sharp and Lee Hamilton (BRC co-chair), Senators Pete Domenici and Chuck Hagel, former NRC chairman Richard Meserve, and former National Security Agency Chief Brent Scowcroft (the other co-chair). On the technical side Exelon CEO John Rowe, MIT Nuclear Department Head Prof. Ernest Moniz, and Allison MacFarlane, an environmental expert from George Mason University, bring a mature practical understanding of the issues.</p>
<p>In its first sessions, in addition to the directives from Secretary Chu, the BRC received testimony from expert witnesses who articulated many of the hurdles that a re-invigorated spent-fuel management program must address. The commission’s process is open to public scrutiny and comment. The issues as they are being laid out for the BRC seem clear, and though challenging, they aren’t insurmountable. But whether the BRC can overcome the hurdles before it and bring about meaningful change to nuclear waste management might depend on the ability of its leaders to focus on a mission that’s both politically and practically achievable.</p>
<p><b>Political Context </b></p>
<p>Understanding this commission’s purpose and timing requires understanding a complex political context.</p>
<p>In 1982, the <i>Nuclear Waste Policy Act</i> established the federal government’s responsibility to provide a place for the permanent disposal of high-level radioactive waste and spent nuclear fuel by 1998. The act also set forth the generators’ responsibility to bear the costs of permanent disposal. As a requirement, a nuclear waste fund was created from charges on nuclear electricity users. Thus, the ratepayers would pay for the development and construction of the needed waste-disposal facilities.</p>
<p>Since 1984, nuclear power ratepayers have paid more than $17 billion into the nuclear waste fund that grew over time to $34 billion and now has a balance of $24 billion. The National Academy of Sciences (NAS) alone has performed about 140 studies since 1956, and spent some $4 billion on siting at Yucca Mountain facilities out of the $13 billion expended to date. With the cancellation of the Yucca Mountain option, the ratepayers have received nothing in return for their massive investment. Representing the utilities and these ratepayers, the National Association of Regulatory Utility Commissioners (NARUC) forcefully articulated the outrage of their constituents at the BRC sessions. They decried the failure of the federal government to meet its obligation under the 1982 act to begin accepting nuclear waste by 1998. Thus the BRC begins its work in the context of the federal government’s $30 billion failure to develop a site for storing the nation’s nuclear waste.</p>
<p>The Yucca Mountain site was shut down at least in part because of the opposition of Senate Majority Leader Harry Reid (D-Nev.). In principle, it could be resurrected if either Senator Reid loses re-election to a candidate who supports the repository, or if NARUC wins a lawsuit it has mounted against the federal government to prevent the shutdown.<sup>1</sup><b> </b>Either outcome could affect the commission’s ultimate recommendation.</p>
<p>Many states and cities are opposed to having nuclear waste facilities within their borders, even though most states currently store such waste. Likewise, Nevada has said no to Yucca Mountain, but recent polls indicate support might be increasing—particularly for facilities that aren’t perceived as merely a dump for nuclear waste.<sup>2</sup> Thus, in spite of broad popular opposition, the prospect for siting nuclear spent-fuel management facilities is difficult, but not hopeless. The BRC heard National Conference of State Legislators spokesperson Sally Young from Maryland and Sen. Domenici both point out there are multiple cities and states interested in housing such facilities, even as they acknowledged that support sometimes dwindles when a concrete proposal is made.<i> (See “<a href="http://www.fortnightly.com/fortnightly/2010/07/nuclear-yimby">Nuclear YIMBY</a>”)</i>.</p>
<p>Turning theoretical support into lasting commitments will require a siting process that’s more attuned to public sentiments than previous processes were, including the possibility of giving cities and towns a veto over such a facility. Defining such a process might prove to be one of the BRC’s most important tasks, if policymakers hope to garner public confidence in any future siting efforts.</p>
<p><b>Buying Time with Interim Storage </b></p>
<p>Although the BRC doesn’t need to specify interim and permanent storage solutions in its recommendations, it does need to redefine the path forward. Several experts, including Kevin Crowley of the National Academy of Sciences (NAS) and Matthew Bunn of Harvard’s Managing the Atom project, have advised the BRC to focus on interim storage of spent fuel from shut-down power plants for the next hundred years, and then to set in motion a new process for permanent storage. Most experts concur that permanent storage in a geologic formation is needed. There’s also agreement that the United States has decades to develop the technical understanding needed to complete the permanent storage facility. With an interim storage facility in place, the public interest would be fully protected in the short term.</p>
<p>The urgent need for a consolidated interim storage facility was highlighted for the BRC by the testimony of Frank Marcinowski, deputy assistant secretary for regulatory compliance in DOE’s Office of Environmental Management. He described the broad and scattered storage for spent nuclear fuel and high-level wastes throughout the United States. Adding to the urgency, Mark Holt of the Congressional Research Service warned that reactor pools have reached their capacity, increasing the immediate need for dry cask storage.</p>
<p>This situation is adversely affecting local communities, because valuable real estate is unusable due to current storage practices. As reactors shut down, abandoned sites such as the 700-acre Palisades site on Lake Michigan are prevented from being converted to new uses by the continued presence of spent-fuel repositories. Michigan Public Service Commissioner Greg White, representing NARUC, pointed out that 10 reactors have been permanently shut down at nine sites. A consolidated facility for transfer and storage of waste from shut-down nuclear plants is a high priority.</p>
<p>There seemed to be a consensus among both witnesses and members of the commission that a step-wise approach to siting would build public confidence and trust. The steps would include establishing a consolidated interim storage facility for shut-down reactors, and establishing a consultative approach to potential permanent disposal in a geologic formation. The consultative approach would move forward with more clarity after regulatory standards have evolved, and, possibly, after new reactor types have reduced the quantity of long-term wastes.</p>
<p>As Bunn put it, “We should not put permanent repositories on an indefinite back-burner, but should establish a credible repository program, in part because this is likely to be important to gaining public acceptance for interim storage sites.”</p>
<p>This is true whatever nuclear fuel-cycle options the United States pursues. Thomas Cochran of the National Resources Defense Council (NRDC) argued that the BRC needs to get the geologic storage program back on track. The prevailing sentiment is that the United States can take time to develop permanent storage with a consolidated interim storage facility so that there will be better understanding of the technologies, and more public support for a long-term solution. How to manage, fund, and develop long-term storage is a vital issue on the BRC agenda.</p>
<p><b>Reprocessing Realities </b></p>
<p>Invited experts speaking at the BRC’s May meeting expressed almost unanimous opposition to reprocessing of spent nuclear fuel—some because of the high costs, some because of the technology involved, and others because of the increased risk of proliferation.</p>
<p>Harvard University’s Bunn put proliferation in perspective when he said: “Reprocessing and recycling using the only technologies now commercially available means separating, fabricating and transporting tons of weapons-usable plutonium every year—when even a few kilograms is enough for a bomb. This inevitably raises risks of nuclear proliferation and nuclear terrorism not posed by direct disposal.”</p>
<p>The BRC heard witnesses say that because of this proliferation risk, reprocessing should be studied but not implemented until there’s more certainty about how to prevent materials from being weaponized, and international agreements are established to manage the risks.</p>
<p>But the issue is more complex than the experts’ testimony indicated. If there’s a great increase in demand for nuclear power, as the commission discussed with DOE Program Analyst Matthew Crozat at its initial meeting, then demand for uranium will increase and reprocessing will become a source of reactor fuel as well as an opportunity to reduce the amount of spent fuel requiring permanent geological storage.</p>
<p>How we treat nuclear wastes in the future might be determined, in part, by whether or not we’ll need the energy contained in the waste. At present, most experts agree that reprocessing is both too expensive and unnecessary, since there seems to be plenty of uranium ore available. That might change, however, and reprocessed fuel might become needed to achieve long-term national energy sufficiency and supply new reactors built to fight climate change.</p>
<p>Reprocessing also might be the best way to get spent fuel into a form that’s safer for long-term disposal. This would be accomplished by removing the long-lived material, leaving fission products that have short half-lives and are easier to store permanently in a geologic formation. Such objectives would require new reactor and reprocessing technologies that haven’t yet been developed. Thus the commission’s recommendations need to allow for a dynamic evolution of response to future events, and must weigh economic and proliferation factors in the context of long-term energy goals.</p>
<p><b>Focusing the Mission </b></p>
<p>The commission’s mandate is very broad and could easily be overwhelming to ordinary mortals. The commission doesn’t have the time to solve every problem of nuclear waste disposal and management. Indeed, experts suggest that some of the more intractable problems of reprocessing, proliferation and permanent geologic storage can, and should, be dealt with over the decades to come.</p>
<p>To achieve effectiveness and results, the commission arguably must narrow its focus. Short-term storage naturally rises to the top of an action agenda. Witnesses speaking at the May BRC meeting expressed the nearly unanimous opinion that dealing with short-term interim storage is the commission’s most important task, along with establishing a management process for addressing the longer term fuel-cycle issues.</p>
<p>Some experts, like Crowley of NAS, advised the BRC that the entire process needs to be revised, and that the DOE effort over the past decade won’t result in a long-term solution because of the narrow way the <i>Nuclear Waste Policy Act</i> mandates solutions. This perspective largely echoes what NAS said two decades ago in a 1990 position paper.<sup>3</sup><b> </b>Experience since then has reinforced the same conclusion.</p>
<p>Two management options emerged from preliminary BRC testimony: Either a new, independent agency with funding directly from the nuclear waste fund, independent of annual Congressional appropriation; or a new corporation to be established and run by the nuclear industry with some kind of federal oversight and funded directly from the nuclear-waste fund.</p>
<p>Tom Sanders of the American Nuclear Society (ANS) called for creating an independent entity to oversee management of the current and expected stockpile of U.S. spent nuclear fuel. And Commissioner Greg White of the Michigan PSC and NARUC urged consideration of other organizational alternatives. He pointed out that Canada has a “well-managed interim storage program in place” with a “nuclear waste management organization, responsible for the repository program, created and managed by the nuclear reactor owners.” (<i>See “Spent Fuel Management Models.”</i>)</p>
<p>During the BRC meeting in May, there seemed to be strong support for turning much of this management over to the private sector—perhaps through the new U.S. Nuclear Waste Management Corp. recently proposed by Senator George Voinovich<sup>4</sup> —or to an independent nuclear-waste management agency separated from DOE, with a reliable funding mechanism independent of annual Congressional appropriations. Norris McDonald of the Nuclear Fuels Reprocessing Coalition called for “a financially autonomous, federal corporation to replace DOE.”</p>
<p>Moving forward, the commission proposed to establish three sub-committees to deal in detail with the questions of storage, reprocessing and disposal. The scope of the sub-committees and membership are being reviewed with Energy Secretary Chu, in advance of the BRC’s next meeting in July.</p>
<p>No matter what approach the BRC takes, the potential scope of its mandate is enormous, time is limited, and focus is essential to success.</p>
</div></div></div><div class="field-collection-container clearfix"><div class="field field-name-field-sidebar field-type-field-collection field-label-above"><div class="field-label">Sidebar:&nbsp;</div><div class="field-items"><div class="field-item even"><div class="field-collection-view clearfix view-mode-full field-collection-view-final"><div class="entity entity-field-collection-item field-collection-item-field-sidebar clearfix">
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<div class="field field-name-field-sidebar-title field-type-text field-label-above"><div class="field-label">Sidebar Title:&nbsp;</div><div class="field-items"><div class="field-item even">Spent Fuel Management Models</div></div></div><div class="field field-name-field-sidebar-body field-type-text-long field-label-above"><div class="field-label">Sidebar Body:&nbsp;</div><div class="field-items"><div class="field-item even"><!--smart_paging_autop_filter--><!--smart_paging_filter--><p>The DOE’s nuclear Blue Ribbon Commission (BRC) is considering changes in the way America handles nuclear spent fuel, and several witnesses at the BRC’s May 2010 meeting in Washington, D.C., outlined alternative management scenarios.</p><p>Ratepayers have spent more than $17 billion since 1984 on the Nuclear Waste Fund, with neither an interim nor a permanent disposal site to show for the investment. Many witnesses speaking at the BRC’s meeting in May expressed outrage over this handling of ratepayer funds, and argued the Nuclear Waste Fund money should be transferred to a new management entity capable of getting facilities built.</p><p>Defining and recommending how this entity is organized and managed, and what its role should be, present key challenges for the BRC. Fortunately, several models exist—some created by America’s national allies.</p><p>• Canada: The Nuclear Waste Management Organization (NWMO) was established in 2002 under Canada’s <i>Nuclear Fuel Waste Act</i> (NFWA) to investigate approaches for managing Canada’s used nuclear power-generation fuel. The NFWA required electricity-generating companies that produce used nuclear fuel to establish a waste-management organization that provides recommendations to the government on the long-term management of used nuclear fuel, and also to establish segregated trust funds to finance the long-term management of the used fuel. To date, three entities with interim storage in on-site dry casks have raised $1.8 billion, and a siting process is in development.</p><p>• Sweden: Nuclear power companies jointly established the Swedish Nuclear Fuel and Waste Management Co. (SKB) in the 1970s. SKB’s assignment is to manage and dispose of all radioactive waste from Swedish nuclear power plants in such a way as to secure maximum safety for human beings and the environment. SKB is responsible for a system of facilities used to handle all waste from the Swedish nuclear power plants. These facilities include a central interim storage facility for spent nuclear fuel (Clab) near Oskarshamn started in 1986, and a final repository for short-lived radioactive waste (SFR) in Forsmark is expected to be proposed in 2010. A poll of residents in the community of Oskarshamm found 84 percent responded in favor of the facility.</p><p>• Finland: In accordance with the <i>Nuclear Energy Act</i>, power companies are responsible for their own waste. Companies must manage existing waste appropriately, and prepare for nuclear waste management to be implemented in the future. They also are responsible for all nuclear-waste management costs. Power companies incorporate the cost of waste management in the price of nuclear electricity and deposit the collected money in a nuclear waste fund, which is managed by the Ministry of Employment and The Economy. By the end of 2008, the fund contained about 1.7 billion euros.</p><p>• U.S. GRI Model: The <i>Nuclear Waste Policy Act </i>of 1982 gave the responsibility for disposal of nuclear wastes to the DOE. There’s no comparable private-sector responsibility for nuclear-waste disposal, but there is an interesting example of the private sector being empowered by the federal government to manage an R&amp;D program that was commercially successful for several decades. The Gas Research Institute, approved by the Federal Power Commission in the 1970s with oversight by the FERC, worked well for several decades and produced commercial products at twice the success rate of the private sector—due, in part, to the oversight of the FERC and the need to justify its investment decisions. This is another model worth considering for managing nuclear wastes in the United States, along with the option to create a separate, independent agency within government.–JB</p><p><b>Endnotes: </b></p><p>1. <i>NARUC v. U.S. Department of Energy and the United States</i>, 10-1074, DC Circuit Court of Appeals, April 2, 2010<i>. </i></p><p>2. <i>Las Vegas Review-Journal</i>/Mason-Dixon poll, April 2010<i>. </i></p><p>3. <i>Rethinking High-Level Radioactive Waste Disposal</i>, National Academy of Sciences, 1990<i>. </i></p><p>4. <i>U.S. Nuclear Fuel Management Corporation Establishment Act of 201</i>0, May 2010, fact sheet<i>.</i></p></div></div></div> </div>
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</div></div></div></div></div><div class="field field-name-field-article-category field-type-taxonomy-term-reference field-label-above clearfix"><h3 class="field-label">Category (Actual): </h3><ul class="links"><li class="taxonomy-term-reference-0"><a href="/article-categories/nuclear">Nuclear</a></li><li class="taxonomy-term-reference-1"><a href="/article-categories/nuclear-fuel-cycle">Nuclear Fuel Cycle</a></li></ul></div><div class="field field-name-field-members-only field-type-list-boolean field-label-above"><div class="field-label">Viewable to All?:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-article-featured field-type-list-boolean field-label-above"><div class="field-label">Is Featured?:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-image-picture field-type-image field-label-above"><div class="field-label">Image Picture:&nbsp;</div><div class="field-items"><div class="field-item even"><img src="http://www.fortnightly.com/sites/default/files/article_images/1007/images/1007-FEA3.jpg" width="1711" height="1204" alt="" /></div></div></div><div class="field field-name-field-fortnightly-40 field-type-list-boolean field-label-above"><div class="field-label">Is Fortnightly 40?:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-law-lawyers field-type-list-boolean field-label-above"><div class="field-label">Is Law &amp; Lawyers:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-tags field-type-taxonomy-term-reference field-label-above clearfix">
<div class="field-label">Tags:&nbsp;</div>
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<a href="/tags/commission">Commission</a><span class="pur_comma">, </span><a href="/tags/congress">Congress</a><span class="pur_comma">, </span><a href="/tags/dc">DC</a><span class="pur_comma">, </span><a href="/tags/department-energy">Department of Energy</a><span class="pur_comma">, </span><a href="/tags/doe">DOE</a><span class="pur_comma">, </span><a href="/tags/exelon">Exelon</a><span class="pur_comma">, </span><a href="/tags/george-voinovich">George Voinovich</a><span class="pur_comma">, </span><a href="/tags/greg-white">Greg White</a><span class="pur_comma">, </span><a href="/tags/harry-reid">Harry Reid</a><span class="pur_comma">, </span><a href="/tags/it">IT</a><span class="pur_comma">, </span><a href="/tags/john-rowe">John Rowe</a><span class="pur_comma">, </span><a href="/tags/michigan-public-service-commission">Michigan Public Service Commission</a><span class="pur_comma">, </span><a href="/tags/michigan-public-service-commissioner-greg-white">Michigan Public Service Commissioner Greg White</a><span class="pur_comma">, </span><a href="/tags/mit">MIT</a><span class="pur_comma">, </span><a href="/tags/naruc">NARUC</a><span class="pur_comma">, </span><a href="/tags/national-association-regulatory-utility-commissioners">National Association of Regulatory Utility Commissioners</a><span class="pur_comma">, </span><a href="/tags/national-resources-defense-council">National Resources Defense Council</a><span class="pur_comma">, </span><a href="/tags/nrc">NRC</a><span class="pur_comma">, </span><a href="/tags/nrdc">NRDC</a><span class="pur_comma">, </span><a href="/tags/nuclear">Nuclear</a><span class="pur_comma">, </span><a href="/tags/nuclear-waste-policy-act">Nuclear Waste Policy Act</a><span class="pur_comma">, </span><a href="/tags/palisade">Palisade</a><span class="pur_comma">, </span><a href="/tags/security">Security</a><span class="pur_comma">, </span><a href="/tags/senate-majority-leader-harry-reid">Senate Majority Leader Harry Reid</a><span class="pur_comma">, </span><a href="/tags/sharp">Sharp</a><span class="pur_comma">, </span><a href="/tags/storage">storage</a><span class="pur_comma">, </span><a href="/tags/yucca-mountain">Yucca Mountain</a> </div>
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Thu, 01 Jul 2010 04:00:00 +0000puradmin13617 at http://www.fortnightly.comPlugging Inhttp://www.fortnightly.com/fortnightly/2010/06/plugging
<div class="field field-name-field-import-deck field-type-text-long field-label-inline clearfix"><div class="field-label">Deck:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Can the grid handle the coming electric vehicle load?</p>
</div></div></div><div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Dean Murphy et al.</p>
</div></div></div><div class="field field-name-field-import-bio field-type-text-long field-label-inline clearfix"><div class="field-label">Author Bio:&nbsp;</div><div class="field-items"><div class="field-item even"><p><a href="mailto:dean.murphy@brattle.com"><b>Dean Murphy</b></a>, <b>Marc Chupka</b>, <b>Onur Aydin</b> and <b>Judy Chang</b> are economists with The Brattle Group.</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - June 2010</div></div></div><div class="field field-name-field-import-image field-type-image field-label-above"><div class="field-label">Image:&nbsp;</div><div class="field-items"><div class="field-item even"><img src="http://www.fortnightly.com/sites/default/files/article_images/1006/images/1006-FEA2-fig1.jpg" width="1366" height="772" alt="" /></div><div class="field-item odd"><img src="http://www.fortnightly.com/sites/default/files/article_images/1006/images/1006-FEA2-fig2.jpg" width="2064" height="952" alt="" /></div><div class="field-item even"><img src="http://www.fortnightly.com/sites/default/files/article_images/1006/images/1006-FEA2-fig3.jpg" width="1366" height="772" alt="" /></div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p>As electric vehicles become commonplace, will the grid be able to handle the extra load? Too many cars plugging in at once might cause disruptions and necessitate costly infrastructure upgrades. Handling the vehicle load in a smart way, however, will ensure a smooth transition to the plug-in future.</p>
<p>Plug-in electric vehicles (PEVs)—powered in part or fully by the electric grid—might offer an opportunity to shift much of the transport sector’s energy demands away from petroleum, reducing dependence on imported oil and improving the environment. If the electric grid can be decarbonized (still an open question), this shift will help to reduce overall carbon dioxide (CO<sub>2</sub>) emissions as well. The potential has drawn much attention from a variety of quarters—including policymakers concerned about climate change and energy security, and vehicle manufacturers wanting to capitalize on a new market. Power system planners concerned about the possible effect of PEVs on the electric system also have begun exploring the issues.</p>
<p>Transportation as a whole uses an immense amount of energy—about two-thirds as much primary energy as consumed by the entire U.S. electric sector—and emits about a third of the nation’s CO<sub>2</sub>. If a large share of the transport sector were to convert to electricity, it could become a huge new electric load that raises many questions, concerns and maybe opportunities for the power sector. If PEVs were to charge up during off-peak times so that they help fill the valleys in the daily load shape and improve the utilization of the existing grid infrastructure, they could be a valuable complement to the power grid. However, if PEVs are adopted in large numbers but do not coordinate with the grid (<i>e.g.</i>, charging at times that add to peak demand or create rapid load ramps)—they could be disruptive and might necessitate significant additional infrastructure and investment.</p>
<p>As PEVs penetrate the transportation industry, they present a range of possible impacts on the U.S. power system.<sup>1</sup> Because the relationships among PEV penetration, charging behavior, electric infrastructure requirements and environmental outcomes might not always be aligned, PEVs pose some interesting tradeoffs that policymakers and the power industry are just beginning to grapple with.</p>
<h4>PEV Market Outlook</h4>
<p>Although electric vehicles were developed in the early days of the automobile, the advantages of the internal combustion engine and petroleum fuels in terms of cost, performance and quick refueling relegated electric vehicles to the sidelines for the 20th century. The commercial introduction of hybrid electric vehicles (HEVs) about a decade ago offered a new way to capture some of the advantages of electric vehicles. HEVs don’t use electricity as a primary fuel; all their power originates with their internal combustion engine, with the battery and electric motor simply storing surplus energy and recovering it later. But they can improve fuel efficiency considerably, and their sales have grown rapidly, making up about 3 percent of U.S. light-duty vehicle sales in 2009, and more in some regions.<sup>2</sup> Most notably, HEVs have opened the door for the plug-in hybrid electric vehicle (PHEV)—essentially an HEV with a much larger battery that can be charged with grid electricity for part of the vehicle’s primary energy needs. PHEVs might in turn re-open the potential for pure battery electric vehicles (BEVs), which forego the internal combustion engine altogether and run solely on grid electricity. For the foreseeable future, most PEVs likely will be PHEVs using a mix of electricity and gasoline.</p>
<p>Although the mass-market PEVs aren’t available just yet, many major auto manufacturers are planning to launch them in the next year or two. Chevrolet is introducing the Volt, Toyota will offer a plug-in version of the Prius hybrid, Nissan is launching its all-electric Leaf, and Ford is planning an electric version of the Focus. As a result, the potential for powering vehicles with grid electricity already has captured the attention of the power industry. For example, the ISO/RTO Council, a consortium of 10 North American independent system operators and regional transmission organizations, recently released an assessment of PEVs and how they might integrate with electric systems.<sup>3</sup> Several regional collaborations of electric utilities and other entities have been formed to promote the development of electric transportation infrastructure, including the Regional Electric Vehicle Initiative in New England and the Regional Plug-In Electric Vehicle Planning process in southern California.<sup>4 </sup></p>
<p>Despite these developments, any forecast of PEV market penetration is highly speculative at the moment. Expectations for how quickly PEVs will penetrate the market depend on their economics compared to gasoline vehicles (including HEVs), their performance, safety, customer acceptance, and public concern about environmental impacts. Depending on assumptions about how these factors will evolve, market-share projections for PEVs range widely.</p>
<p>PEVs currently face a significant economic hurdle due primarily to the high cost of batteries, even accounting for recent and forecast improvements in battery cost and performance. Although electricity is much less expensive than gasoline per mile travelled, the operating cost savings are modest relative to the incremental initial purchase cost of a PEV. Fueling a 35-mpg gasoline vehicle—which would match the 2016 CAFE standard—with $3/gallon gasoline costs about 8.6¢ per mile, or $1,285 per year. In comparison, a PEV that uses 250 watt-hours per mile at 12¢/kWh, assuming it has sufficient electric range to run entirely on electricity, has fuel costs of about 3¢ per mile, or $450 per year. While this is an operating cost savings of 65 percent, or more than $800 per year, the incremental purchase cost of the PEV likely will be many thousands of dollars. Many PEVs will be plug-in hybrids that still rely on gasoline for part of their energy needs; while their smaller battery reduces the purchase cost premium, it also provides a shorter electric range and correspondingly smaller fuel savings.</p>
<p>The PEV’s fuel savings are smaller when compared to higher-mileage non-plug-in vehicles such as HEVs. Until battery costs decline considerably, or gasoline prices rise dramatically, it’s unlikely that PEVs will offer significant cost advantages over non-electric vehicles, so they probably will be attractive to only a limited segment of drivers. These may be the same drivers that currently favor more fuel-efficient vehicles (including HEVs) and whose driving patterns reflect a high proportion of urban travel. While this factor might complicate the estimation of gasoline savings from PEV penetration (<i>i.e.</i>, because PEVs might tend to replace fuel-efficient conventional vehicles), it does suggest a distinct geographic pattern of initial PEV concentration—largely in urban areas on the East and West coasts. However, PEVs might be embraced for reasons beyond a strict cost advantage, and supportive public policies coupled with innovative designs and effective marketing could help to broaden their appeal.</p>
<p>DOE’s Energy Information Administration (EIA) has estimated that the annual sales of PEVs will grow to almost 140,000 vehicles by 2015, and 400,000 vehicles by 2030, supported by tax credits enacted in 2008—currently $2,500 per vehicle, plus $417 per kWh of battery capacity in excess of 5 kWh. An MIT report assumes plug-in hybrids will account for 2-3 percent of new vehicle sales by 2020, and 10 percent by 2030.<sup>5</sup> A much more optimistic scenario developed by the Electric Power Research Institute (EPRI) assumes 35 percent for 2020, and 50 percent for 2030.<sup>6</sup> Of course, for a new technology with adoption rates ramping up, its share of the overall vehicle fleet will be considerably lower than its share of new vehicle sales, because the fleet is only gradually replaced by new vehicles.</p>
<p>The National Research Council released a study that projected a “maximum practical” overall fleet penetration of PHEVs of about 13 percent by 2030, with a “more probable” penetration of less than 5 percent by that time.<sup>7</sup> The ISO/RTO Council’s March 2010 report estimates 1 million PEVs will be sold within five to 10 years, also concluding that early adoption would cluster in urban centers. The faster trajectory leads to a total of about 2.5 million vehicles by 2020—about 1 percent of the light duty vehicle fleet, though with a fair amount of geographic concentration that could mean a larger impact in some areas.</p>
<p>Overall, the market penetration of PEVs likely will be limited to a few percent of new vehicle sales over the next decade, and a smaller share of the vehicle fleet. If some of the barriers to PEV adoption can be overcome quickly, and consumer acceptance is high, it appears possible, albeit very optimistic, that PEVs might achieve as much as a 20-percent share of new vehicle sales and 5 percent of the vehicle fleet in some urban regions by 2020, potentially growing more quickly thereafter. But there are potential grid implications of this optimistic level of PEV penetration over the next decade.</p>
<h4>Impact on the Grid</h4>
<p>A study by Pacific Northwest National Laboratory showed that up to 84 percent of U.S. cars, pickup trucks, and SUVs theoretically could be converted to plug-in hybrids without requiring additional electric infrastructure (<i>i.e.</i>, by charging vehicles only at off-peak times to utilize electric generating capacity that’s otherwise idle).<sup>8</sup> However, it’s unlikely that all PEVs would charge exclusively during off-peak periods. In fact, their demand on the regional power infrastructure depends greatly on when, and how quickly, drivers charge their vehicles. A 2008 Oak Ridge National Laboratory study estimated that the increase in energy demand would be about 1 to 2 percent in 2020, and about 2 to 5 percent in 2030, based on a very aggressive assumed fleet penetration of 10 percent by 2020, and 25 percent by 2030.<sup>9</sup> That report also found that faster charging, if concentrated in the evening hours, could increase peak electricity demand substantially. In some extreme scenarios examined, where all vehicles utilize rapid charging coincident with system peak, peak demand could increase as much as 10 percent in 2020, and more than 25 percent in 2030. However, this study also found that if PEVs are charged at times less coincident with the existing system peak (<i>i.e.</i>, charged later or more slowly, or not all at the same time), they would have a much more modest effect on peak load, and potentially no effect at all if charging occurs entirely off-peak.</p>
<p>Although it’s difficult to predict charging patterns confidently in the absence of actual customer experience with PEVs, natural diversity in drivers’ schedules and habits might make either of these extremes—all on-peak charging or all off-peak charging—unlikely.</p>
<p>Access to charging spots is an important factor shaping drivers’ charging patterns. Most PEVs likely will be charged at home in evening and night-time hours. The availability of public charging spots (<i>e.g.</i>, workplaces, public garages, street charging) will increase the diversity of charge times and might increase the total amount of electricity used; charging twice daily means using more electricity and less gasoline in a PHEV, though it also will encourage more charging during high-load daytime hours.</p>
<p>Take for example several hypothetical charging profiles that illustrate how the incremental PEV load might be distributed across the hours of the day, with the area under each summing to 100 percent over the day (<i>see Figure 1</i>). The “evening concentrated” profile assumes that all drivers begin charging their batteries more or less simultaneously at 5 to 6 p.m. using rapid chargers that give a full charge in two hours. “Evening diversified” assumes that some drivers begin charging at 5 to 6 p.m. and some start several hours later, using slower chargers that spread the load across eight hours. In “increased work access,” half of the charging starts during morning at 8 to 9 a.m., and the other half starts at 5 to 6 p.m. In “off-peak,” charging occurs at night, starting from 10 to 11 p.m. and continuing through the early morning. These are purely hypothetical demonstrations of the potential incremental load shape; PEVs’ actual charging profiles will be driven by drivers’ information, habits, convenience and electric pricing schemes.</p>
<p>With substantial PEV penetration, the evening-concentrated profile might create concern for an electric system, since it concentrates a large new energy demand at or near system peak. Increased daytime charging access (<i>e.g.</i>, at work) might make some PEV load coincide more directly with existing system peaks, though it also might help to diversify the charging load across time. Further, it might create additional stresses on urban distribution systems by concentrating additional loads in areas and times that already have high loads. Night-time charging seems to be the best complement to current system conditions, though if charging loads were concentrated sufficiently, they could conceivably create a secondary daily peak.</p>
<p>A tangible example considers the potential impact of these different charging patterns on simulated New England electricity demand in 2020. The PEV demand is overlaid on both summer and winter peak day load shapes (assuming 5-percent New England fleet penetration by PEVs that get half their energy from electricity, on average) (<i>see Figure 2</i>). If charging is heavily concentrated at or near system peak on a system like New England’s (<i>e.g.</i>, the evening-concentrated charging pattern), even relatively modest PEV penetration might increase system capacity needs by several percent. Other charging patterns that involve charging later or spreading it over longer periods—some of which may occur naturally—greatly reduce or eliminate the impact on system capacity needs. The increased-work-access charging pattern adds slightly to capacity needs because it adds load at system peak times, though the increment is small because the load is distributed across many hours. The other patterns have no effect on peak load at all.</p>
<p>The seasonality of the daily load pattern also can be important. In New England, system load usually peaks in summer in mid-afternoon hours. This is several hours before much of the likely PEV load, if drivers charge at home after work. But the winter peak occurs later in the evening, more coincident with the likely PEV load. Since New England is a summer-peaking region overall, the coincidence of PEV loads with winter peak might not be a major concern. But on a winter-peaking system, an unmanaged PEV charging profile could increase overall system capacity requirements even at low PEV penetration, giving an incentive to more aggressively manage PEV loads.</p>
<p>To encourage charging during off-peak hours likely would involve technological and pricing solutions. Technological solutions include smart-charging systems that can consider electrical system preferences while meeting drivers’ needs. Pricing solutions, such as dynamic pricing of electricity, could enhance consumers’ incentives for off-peak charging by offering different prices for peak and off-peak electricity. Both approaches should help to steer drivers toward better use of the electric system, though it isn’t clear how PEV owners would respond. Depending on how prices are structured, the potential savings associated with dynamic pricing might be relatively small and could be ignored, and technological solutions might be bypassed if they don’t meet drivers’ needs.</p>
<p>The potential to integrate PEVs into the future smart grid so that they can respond dynamically to help balance the grid’s needs, becoming a controllable resource as well as a new customer and perhaps even compensating for the variability of renewable generation sources, is a particularly attractive long-term prospect. In fact, a recent article on variable renewable energy integration states: “Plug-in electric vehicles promise to increase minimum loads at night—making use of surplus wind-energy generation—and to offer fast and accurate response to high variability in wind net load, as needed by the system operator.”<sup>10</sup> However, most analysts regard widespread adoption of such vehicle-to-grid (V2G) technology as many years more distant, recognizing the technological and regulatory barriers that must be overcome before it can be deployed widely.</p>
<p>Although the impact of likely PEV penetration rates on overall system demand is modest, if PEV adoption is highly localized (<i>e.g.</i>, in affluent neighborhoods), the additional charging load potentially could add stresses on the local distribution system. The expected modest PEV numbers, coupled with the fact that easily observable PEV sales give advance warning of aggregate fleet penetration, might help utilities to foresee and deal with these issues. However, this is an area that would benefit from additional research and real-world experience, and active utility intervention ultimately might be needed to prevent or address localized distribution issues.</p>
<h4>Long Tailpipe?</h4>
<p>From an environmental perspective, switching from gasoline to electricity as a transport fuel means trading the emissions of a gasoline-powered internal combustion engine for those of the marginal electric generator at the time the PEV is charged.<sup>11</sup> In addition to moving those emissions geographically from the tailpipe of the vehicle to the generator’s smokestack, the quantities emitted will differ. The CO<sub>2</sub> emitted from a gasoline vehicle is similar to that released by charging a PEV with power from a coal-fired plant. Coal has about the highest CO<sub>2</sub> emissions among common generation types, so in many regions and circumstances (<i>i.e.</i>, when some other resource that emits less CO<sub>2</sub>, such as a gas plant, is on the margin), a PEV will emit less CO<sub>2</sub> than a gasoline vehicle. This generally is the case in New England, where gas-fired units are on the margin in most hours, emitting CO<sub>2</sub> at about half the rate of coal-fired power.</p>
<p>The annual CO<sub>2</sub> emissions of a conventional gasoline vehicle (at 25 to 45 mpg) can be compared with those of a PEV under several alternative charging circumstances (<i>see Figure 3</i>). For a more direct comparison, the PEV is assumed to be all-electric rather than a plug-in hybrid. If the PEV is charged when a coal plant is on the margin, its CO<sub>2</sub> emissions will be similar to those of a gasoline vehicle. Note that the range of PEV emissions when charging with coal corresponds to a range of coal plant efficiency—a less efficient coal plant emits more CO<sub>2</sub>. If a gas plant is on the margin, the PEV emits much less CO<sub>2</sub>. On most systems, the marginal emissions rate differs over the hours of the day, so the PEV’s CO<sub>2</sub> emissions might depend on the particular charging pattern, and would be an average of the marginal emission rates during the charging period. The right-most bar on <i>Figure 3 </i>illustrates the CO<sub>2</sub> emissions of a PEV charged on the simulated 2020 New England power system; the range reflects the emissions of different charging profiles, accounting for the marginal unit’s emissions in each charging hour. Because the New England power system has gas on the margin in the large majority of hours, a New England PEV would emit significantly less CO<sub>2</sub> than a gasoline vehicle, and its emissions don’t depend greatly on the charging profile.</p>
<p>This might not be true in all regions, particularly those dominated by coal. In some regions such as the Midwest, where coal-fired units are often marginal in off-peak hours, off-peak charging may forego much of the potential CO<sub>2</sub> reductions. Even in such regions, however, to the extent the power grid is decarbonized over time through the addition of less carbon-intensive resources (<i>e.g.</i>, gas, renewables, hydro, nuclear) and reduced reliance on coal, a PEV’s emissions can fall over time.</p>
<p>The effect of PEVs on the emissions of other pollutants, such as nitrogen oxides (NOx) and sulfur dioxide (SO<sub>2</sub>), depends heavily on the emissions controls in place—the vehicle’s own emission controls for a gasoline vehicle, and the emission controls on the marginal generator for the PEV. As with CO<sub>2</sub>, the power system’s marginal emission rates of other pollutants can vary considerably with time—and certainly from one electric system to another—depending on which unit is on the margin. In the New England analysis, NO<sub>x</sub> emissions of a PEV generally were similar or slightly lower than those of a gasoline vehicle. SO<sub>2</sub> emissions were a bit higher, because gasoline contains little sulfur and some generator types, particularly coal and oil-fired units, do emit SO<sub>2</sub> and are sometimes on the margin. More generally, electric generating units might be farther from the urban areas that are most sensitive to air quality, both geographically and temporally, compared to the internal combustion engines which emissions they would displace, though again this may depend on the particular circumstances.</p>
<h4>Time to Plan</h4>
<p>PEV penetration of the vehicle fleet is likely to be relatively limited for the next decade and probably beyond, in part because the high initial cost of batteries likely will continue to outweigh the potential fuel-cost savings. Due to the natural lag in replacing the existing fleet, fleet penetration by PEVs will be gradual even if they achieve a relatively high share of new vehicle sales. Further, if PEV sales are high, this will be observable before PEVs take over a large share of the fleet, giving the industry some opportunity to plan accordingly.</p>
<p>The energy demand that PEVs might place on the power system isn’t particularly great even at higher fleet penetration levels, and will be quite modest at more likely penetration levels. The potential effect of PEVs on electric peak loads might be another matter. Even at plausible penetration levels, PEVs could affect system peak loads if many of them are charged quickly at or near peak load times, though natural diversity in users’ schedules and habits might mitigate some of this concern. This might make charging patterns and the timing of PEV load a more important factor for the power industry than overall PEV penetration. Beyond trying to understand PEV market penetration, which of course is important, we need further study to understand users’ charging behavior. It will be particularly important to understand what natural charging behavior would be, how it will respond to the electric industry’s attempts to influence it, and how this might interact with the design of vehicles and chargers. The effect in any particular region may depend importantly on the details of system load shape and seasonality, and in some cases might warrant efforts to understand and perhaps influence charging behavior even at fairly low penetration levels. Again, because of the lag between sales share and fleet penetration levels, power system planners might have an opportunity to learn from early experience with PEVs’ charging patterns in actual use, prior to their becoming a major source of load.</p>
<p> </p>
<h4>Endnotes:</h4>
<p>1. This article draws on research performed in the context of a state-level integrated resource plan (<i>Integrated Resource Plan for Connecticut</i>, The Brattle Group, The Connecticut Light and Power Co., and The United Illuminating Co., Jan. 1, 2010). While that research focused on planning for Connecticut and the New England electric system, the observations have similar relevance for other regions.</p>
<p>2. U.S. DOE, Alternative Fuels and Advanced Vehicles Data Center, at: <i><a href="http://www.afdc.energy.gov" target="_blank">www.afdc.energy.gov</a>.</i></p>
<p>3. <i>Assessment of Plug-in Electric Vehicle Integration with ISO/RTO Systems</i>, ISO/RTO Council and KEMA Inc., March 2010.</p>
<p>4. See <i><a href="http://www.newrules.org/environment/rules/plugin-electric-vehicles/plugin-electricplanning-southern-california" target="_blank">http://www.newrules.org/environment/rules/plugin-electric-vehicles/plugin-electricplanning-southern-california</a>.</i></p>
<p>5. Heywood, J. <i>et al</i>., <i>On the Road in 2035: Reducing Transportation’s Petroleum Consumption and GHG Emissions</i>. MIT Laboratory for Energy and the Environment, Report No. LFEE 2008-05 RP, 2008.</p>
<p>6. Duvall, M., E. Knipping, <i>Environmental Assessment of Plug-In Hybrid Electric Vehicles. Volume 1: Nationwide Greenhouse Gas Emissions</i>, Report No. 1015325, Electric Power Research Institute, 2007.</p>
<p>7. National Research Council Committee on Assessment of Resource Needs for Fuel Cell and Hydrogen Technologies, <i>Transition to Alternative Transportation Technologies—Plug-in Hybrid Electric Vehicles</i>, National Academy of Sciences, 2009.</p>
<p>8. Kintner-Meyer<i> et al.,</i><i>Impacts Assessment of Plug-in Hybrid Vehicles on Electric Utilities and Regional U.S. Power Grids</i>, Part 1: Technical Analysis, Pacific Northwest National Laboratory, 2007.</p>
<p>9. Hadlew, S.W. and A. Tsvetkova, <i>Potential Impacts of Plug-in Hybrid Electric Vehicles on Regional Power Generation</i>, ORNL/TM-2007/150, Oak Ridge National Laboratory, 2008.</p>
<p>10. Milligan, Porter, DeMeo, Denholm, Holttinen, Kirby, Miller, Mills, O’Malley, Schuerger and Soder, “Wind Power Myth Debunked,” <i>IEEE Power and Energy Magazine</i>, November/December 2009.</p>
<p>11. A PEV’s electric emissions usually should be characterized in terms of the electric generator that is on the margin (<i>i.e.</i>, the unit that will increase or decrease its output in response to a change in load) when the PEV is charging, rather than the system average emissions.</p>
</div></div></div><div class="field-collection-container clearfix"><div class="field field-name-field-sidebar field-type-field-collection field-label-above"><div class="field-label">Sidebar:&nbsp;</div><div class="field-items"><div class="field-item even"><div class="field-collection-view clearfix view-mode-full field-collection-view-final"><div class="entity entity-field-collection-item field-collection-item-field-sidebar clearfix">
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<div class="field field-name-field-sidebar-title field-type-text field-label-above"><div class="field-label">Sidebar Title:&nbsp;</div><div class="field-items"><div class="field-item even">How Big an Effect?</div></div></div><div class="field field-name-field-sidebar-body field-type-text-long field-label-above"><div class="field-label">Sidebar Body:&nbsp;</div><div class="field-items"><div class="field-item even"><!--smart_paging_autop_filter--><!--smart_paging_filter--><p>As a thought experiment, imagine that all U.S. passenger cars—excluding light trucks and SUVs, which are less likely PEV candidates—could be converted overnight to run purely on electricity. The electric energy required to charge them would be only about 13 percent of total 2009 U.S. electricity consumption, which was 3,723 TWh:</p><p><i>130 million cars * 15,000 miles/year * 250 watt-hours/mile = 487 TWh/year </i></p><p>Further, for a new vehicle type, its penetration in the vehicle fleet trails its share of new vehicle sales (new vehicles only slowly replace old ones; cars last about 15 years). To make the hypothetical only slightly less unrealistic, suppose PEVs quickly achieved 100 percent of new car sales, replacing about 7 percent of the existing auto fleet each year. The electric energy needed to power each year’s new cohort of PEVs would be about 0.9 percent of current total electricity demand; think of this as adding about 0.9 percent to electric load growth. In that scenario, it would take about 15 years for the PEV load to equal 13 percent of today’s total electricity demand.</p><p>For the foreseeable future, plug-in hybrids, which use electricity for part of their energy needs and burn gasoline for the balance, likely will be the dominant type of PEV, rather than all-electric vehicles. A plug-in hybrid with a 30-mile electric range (PHEV-30) can rely on electricity for about half of its energy; a shorter range vehicle, which may be more common, uses less electricity and more gasoline. If all cars were PHEV-30s, the electric energy requirements would increase by only about half as much.</p><p>Of course, it isn’t remotely plausible that PEVs could achieve this level of penetration. It’s quite optimistic to imagine that they would achieve even 10 percent of vehicle sales in the near future, so these illustrative effects must be scaled back much further still.– <span><span class="bolditalic">DM</span></span></p></div></div></div> </div>
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</div></div></div></div></div><div class="field field-name-field-article-category field-type-taxonomy-term-reference field-label-above clearfix"><h3 class="field-label">Category (Actual): </h3><ul class="links"><li class="taxonomy-term-reference-0"><a href="/article-categories/evs-storage-0">EVs &amp; Storage</a></li></ul></div><div class="field field-name-field-members-only field-type-list-boolean field-label-above"><div class="field-label">Viewable to All?:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-article-featured field-type-list-boolean field-label-above"><div class="field-label">Is Featured?:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-image-picture field-type-image field-label-above"><div class="field-label">Image Picture:&nbsp;</div><div class="field-items"><div class="field-item even"><img src="http://www.fortnightly.com/sites/default/files/article_images/1006/images/1006-FEA2.jpg" width="1500" height="1160" alt="" /></div></div></div><div class="field field-name-field-fortnightly-40 field-type-list-boolean field-label-above"><div class="field-label">Is Fortnightly 40?:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-law-lawyers field-type-list-boolean field-label-above"><div class="field-label">Is Law &amp; Lawyers:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-tags field-type-taxonomy-term-reference field-label-above clearfix">
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<a href="/tags/bev">BEV</a><span class="pur_comma">, </span><a href="/tags/doe">DOE</a><span class="pur_comma">, </span><a href="/tags/eia-0">EIA</a><span class="pur_comma">, </span><a href="/tags/electric-power-research">Electric Power Research</a><span class="pur_comma">, </span><a href="/tags/electric-power-research-institute">Electric Power Research Institute</a><span class="pur_comma">, </span><a href="/tags/electric-power-research-institute-epri">Electric Power Research Institute (EPRI)</a><span class="pur_comma">, </span><a href="/tags/energy-information-administration-0">Energy Information Administration</a><span class="pur_comma">, </span><a href="/tags/epri">EPRI</a><span class="pur_comma">, </span><a href="/tags/ev">EV</a><span class="pur_comma">, </span><a href="/tags/evs">EVs</a><span class="pur_comma">, </span><a href="/tags/ford">Ford</a><span class="pur_comma">, </span><a href="/tags/iso">ISO</a><span class="pur_comma">, </span><a href="/tags/it">IT</a><span class="pur_comma">, </span><a href="/tags/mit">MIT</a><span class="pur_comma">, </span><a href="/tags/oak-ridge-national-laboratory">Oak Ridge National Laboratory</a><span class="pur_comma">, </span><a href="/tags/pacific-northwest">Pacific Northwest</a><span class="pur_comma">, </span><a href="/tags/pev">PEV</a><span class="pur_comma">, </span><a href="/tags/phev">PHEV</a><span class="pur_comma">, </span><a href="/tags/plug-electric-vehicle">Plug-in electric vehicle</a><span class="pur_comma">, </span><a href="/tags/plug-electric-vehicles-pevs">Plug-in electric vehicles (PEVs)</a><span class="pur_comma">, </span><a href="/tags/rto">RTO</a><span class="pur_comma">, </span><a href="/tags/v2g">V2G</a> </div>
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Tue, 01 Jun 2010 04:00:00 +0000puradmin14214 at http://www.fortnightly.comPeople (November 2009)http://www.fortnightly.com/fortnightly/2009/11/people-november-2009
<div class="field field-name-field-import-category field-type-text field-label-inline clearfix"><div class="field-label">Category:&nbsp;</div><div class="field-items"><div class="field-item even">People</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - November 2009</div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p><span class="boldred">New Opportunities: </span><b>El Paso Electric</b> promoted <b>George A. Williams</b> to senior v.p. and <b>COO. J. Frank Bates</b>, who has served as president and COO, will continue as president until retirement in March 2010.</p>
<p><b>Idaho Power</b> promoted <b>Darrel Anderson</b>, IDACORP and Idaho Power’s senior v.p. of administrative services and CFO, to executive v.p. of administrative services and CFO. <b>Dan Minor</b>, Idaho Power’s senior v.p. of delivery, is promoted to executive v.p. of operations. <b>Lisa Grow</b>, v.p. of delivery engineering and operations took on new responsibilities as senior v.p. of power supply. <b>Vern Porter</b>, general manager of power supply is promoted to v.p. of delivery engineering and operations.</p>
<p><b>ConEdison Solutions</b> hired <b>Jim Mueller</b> as v.p. of customer operations. He had been with the parent company, Consolidated Edison Co. of New York.</p>
<p><b>Exelon Corp. </b>appointed<b> John Stough </b>as v.p. and chief development officer for Exelon Transmission Co., a new venture on transmission lines. He joins the company from <strong>American Electric Power</strong>.<b> </b></p>
<p><b>PPL Corp. </b>promoted<b> J. Matt Simmons </b>to chief risk officer from v.p. and corporate contoller.<b> </b></p>
<p><b>Constellation Energy</b> hired <b>Christopher J. Close</b> as CFO for Constellation Energy Resources, its commercial business division. He was v.p. of finance for Exelon Generation. <b>Robert (Bob) J. Gauch Jr.</b> was appointed v.p., credit workout, a newly created position. He was with Citibank.</p>
<p><b>The Organization of PJM States</b> elected <b>Steven A. Transeth</b> as president. He is a commissioner with the Michigan Public Service Commission.</p>
<p><b>Electric Power Research Institute</b> (EPRI) hired <b>Carolyn Shockley</b> as v.p. of fossil generation. EPRI’s <b>Bryan Hannegan </b>will lead an expanded renewable energy effort and will continue as head of EPRI’s environmental sector.</p>
<p><b>The American Wind Energy Association</b> hired <b>Chris Chwastyk</b> as v.p. of federal legislative affairs. He was chief of staff to Texas Congressman <b>Chet Edwards. </b></p>
<p><b>Andrews Kurth LLP</b> announced that <b>Scott A. Brister</b> joined the firm as partner. He was a justice at the Texas Supreme Court.</p>
<p><b>Dickstein Shapiro</b> announced that <b>Michael F. Cusick</b> joined the firm as a partner in its energy practice.</p>
<p><b>McDermott Will &amp; Emery LLP</b> hired <b>David Birchall</b> as a partner at its London office. He is with the firm’s global energy practice.</p>
<p> </p>
<p><span class="boldred">In Memoriam: </span><b>The Illinois Institute of Technology</b> announced the passing of <b>Henry Linden</b>, a faculty member and <b>Max McGraw</b> Distinguished Professor, member of the advisory board of the Wanger Institute for Sustainable Energy Research and the director of the IIT Energy + Power Center.</p>
<p> </p>
<p><span class="boldred">Boards of Directors: </span><b>Spectra Energy Partners, LP,</b> appointed two new directors to the board of its general partner. <b>Theopolis Holeman</b> is group v.p. of Spectra Energy Corp.’s U.S. operations and <b>J.D. Woodward III </b>is president of Woodward Development.</p>
<p><b>American Electric Power</b> elected <b>James F. Cordes</b> to its board. He is retired executive v.p. of The Coastal Corp.</p>
<p><b>Progress Energy</b> elected to its board <b>John D. Baker II</b>, the president and CEO of Patriot Transportation Holding.</p>
<p><b>NSTAR </b>appointed <b>James S. DiStasio</b> to its board. He is a retired partner of Ernst &amp; Young.</p>
<p><b>Entergy</b> elected <b>Stewart C. Myers</b> to its board. He is the <b>Robert C. Merton Professor </b>of Financial Economics at the MIT Sloan School of Management.</p>
<p><b>Centrica</b> announced that <b>Nick Luff,</b> finance director and <b>Mark Hanafin</b>, managing director of Centrica Energy and Europe, were appointed directors of venture production and assumed positions on the board.</p>
<p> </p>
<p><i>We welcome submissions to People, especially those accompanied by a high-resolution color photograph. E-mail to: <a href="mailto:people@pur.com">people@pur.com</a>.</i></p>
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Sun, 01 Nov 2009 04:00:00 +0000puradmin14264 at http://www.fortnightly.comReducing Lifecycle Expenditureshttp://www.fortnightly.com/fortnightly/2009/05/reducing-lifecycle-expenditures
<div class="field field-name-field-import-deck field-type-text-long field-label-inline clearfix"><div class="field-label">Deck:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Total cost of ownership accounting optimizes long-term costs.</p>
</div></div></div><div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Steven McCabe et al.</p>
</div></div></div><div class="field field-name-field-import-category field-type-text field-label-inline clearfix"><div class="field-label">Category:&nbsp;</div><div class="field-items"><div class="field-item even">Business &amp; Money</div></div></div><div class="field field-name-field-import-bio field-type-text-long field-label-inline clearfix"><div class="field-label">Author Bio:&nbsp;</div><div class="field-items"><div class="field-item even"><p><b>Steven McCabe</b> (<a href="mailto:stmccabe@deloitte.com">stmccabe@deloitte.com</a>) is senior manager with Deloitte. <b>Kwasi Mitchell</b> and <b>Nathan Ives</b> are managers with the firm.<b> </b></p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - May 2009</div></div></div><div class="field field-name-field-import-image field-type-image field-label-above"><div class="field-label">Image:&nbsp;</div><div class="field-items"><div class="field-item even"><img src="http://www.fortnightly.com/sites/default/files/article_images/0905/images/0905-BIZ-fig1.jpg" width="2068" height="497" alt="" /></div><div class="field-item odd"><img src="http://www.fortnightly.com/sites/default/files/article_images/0905/images/0905-BIZ-fig2.jpg" width="1379" height="1789" alt="" /></div><div class="field-item even"><img src="http://www.fortnightly.com/sites/default/files/article_images/0905/images/0905-BIZ-fig3.jpg" width="2067" height="953" alt="" /></div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p>A large regional utility forfeited significant operating revenues after it replaced pulverizers at several of its coal-fired power plants. Because the replacement pulverizers were sized to operate at 100-percent capacity during operations using the coal typically procured by the utility, upgraded plants had to be derated following a change to lower BTU-rated fuel.</p>
<p>If utility decision makers had used a total cost of ownership (TCO) framework, they could have avoided this situation. An operations and maintenance cost assessment would have revealed the operational effect of the fuel change, allowing the company to consider oversized pulverizers to accommodate lower-grade fuels and thereby maintain the power plant’s capacity.</p>
<p>A confluence of market, regulatory, and technical factors will drive sustained levels of capital investment across each segment in the utility value chain for the next 10 years. The ongoing credit crisis significantly increases both the cost of, and competition for, capital that will force numerous utilities to reevaluate near-term capital expenditures.<sup><sub>1</sub></sup> During these unprecedented times, it’s increasingly important that utilities focus on reducing lifecycle expenditures, while executing capital projects and not narrowly focusing on short-term procurement gains. A near-term focus on acquisition costs can result in uninformed decision making that is misaligned with corporate goals, regulatory requirements and investor demands.</p>
<p>The implementation of the TCO method during a long-term capital project’s planning phase <i>(see Figure 1)</i> ensures asset-expenditure decisions are well informed and balanced with corporate, regulatory and investor demands. This method is a supply-chain management leading practice; providing a wide-ranging view of the costs associated with asset ownership. TCO classifies costs, direct or indirect, incurred throughout the acquisition, operation and maintenance, or retirement of an asset <i>(see Figure 2)</i>. Traditionally, there has been little difficulty in identifying acquisition costs. In fact, acquisition costs (specifically purchase price) are frequently the sole basis for making purchasing decisions, while often accounting for less than half of total asset costs.<sup><sub>2</sub></sup> Employing TCO to identify less obvious lifecycle costs aids in early identification of best-fit purchasing decisions and long-term cost savings across the project and ultimately the asset lifecycle.<sup><sub>3</sub></sup></p>
<p>A cross-functional team of supply chain, operations, maintenance, engineering, finance, and project-management personnel should conduct the TCO analysis. The team works collaboratively to develop a comprehensive cost model for the asset to be installed during the project and provides estimates for each relevant cost category <i>(see Figure 3)</i>. A distinct cost model is developed for each supplier and scenario under consideration while estimates are based upon historical data and detailed market analysis. After completing this detailed analysis, the team is capable of making well-informed purchasing recommendations, identifying areas for potential cost reductions, and quantifying the long-term value associated with their recommendations. Furthermore, cost model completion enables the team clearly to communicate the rationale behind specific purchasing decisions to key stakeholders so they understand the key elements that have been considered.</p>
<p>Employing this structured approach provides visibility to both near-term budget and long-term cost implications. Successful implementation of TCO and complimentary strategic sourcing leading practices can result in long-term savings of 10 to 20 percent.<sup><sub>4</sub></sup> Most important, use of TCO improves communication of project risks and cost drivers, both internally and with external regulatory agencies and investors. Because of the decreased investor risk tolerance resulting from the current economic downturn, this increased transparency and clarity in decision making displays a focus on operational excellence that can result in favorable treatment from regulatory agencies and gain preferred access to capital.</p>
<h4>Large Capital Projects</h4>
<p>TCO applicability to large capital projects by project lifecycle phase can be demonstrated by exploring material and equipment cost drivers. Currently, numerous utilities employ practices in which large spend materials are procured during the project’s planning and design phase with a strong emphasis on acquisition cost and lead time. There’s moderate coordination of large spend materials resulting in some saving efficiencies. Frequently, moderate to low-spend items are purchased in an <i>ad-hoc</i> fashion throughout the remaining project phases with emphasis placed solely on delivery timing. This ordering just-in-time mentality detrimentally impacts the project budget by increasing expediting and handling costs. Additionally, it prevents the supply-chain organization from fully leveraging supplier contracts and developing an optimized procurement strategy across the entire suite of corporate capital projects.</p>
<p>In contrast, using the TCO method provides innovative opportunities for reducing the cost of asset ownership. During the planning and design phase, stringent adherence to material standardization codes maintains procurement leverage and minimizes project and corporate inventory levels for design materials, associated tools, and spare parts. Collaborative analysis between design engineers and supply-chain staff provides a detailed understanding of the impact that project-design decisions have on the overall project cost to the organization. For example, the analysis should include a simple comparison of the cost of using a different 100-hp motor for a specific project by quantifying the additional design time due to unfamiliarity with the motor, the inventory expenses for alternate replacement parts, and procurement costs associated with purchasing a previously unstocked SKU.</p>
<h4>Labor Resources</h4>
<p>TCO analysis also may be extended to labor resources. Few utilities have an integrated approach to sourcing and utilizing contracted labor for each work stream. Typically, utilities develop sourcing agreements for specialized services such as vegetation management, but then contract engineering and field labor as needed during the procurement phase of the project. Again, this just-in-time approach poses significant budget and schedule risks as resources may not be available or may command a significant premium because of a tight regional labor market.</p>
<p>The TCO method may be used to frame a discussion on labor needs across key business units and the associated cost penalties of employing a just-in-time approach. In conjunction with precise planning and scheduling practices, contractor resource needs can be determined during a project’s feasibility or planning and design phases. Moving the discussion into these phases provides opportunities for leveraging resources across capital projects and entering negotiations with suppliers well before peak staffing periods. A comparison of labor expenses for contracted resources used on multiple projects instead of the traditional one-project-at-a-time approach provides the information required for a detailed resourcing discussion among engineering, operations, maintenance, finance, and supply-chain staffs. Additionally, applying the TCO model may uncover other innovative strategies including opportunities to fund worker cross training that increases competition, or creating an apprenticeship program with local technical and vocational colleges to increase labor supply. Depending on regional labor market economics, TCO reveals the long-term advantages such programs can have on decreasing labor costs while simultaneously increasing resource skill levels to improve capital project execution.</p>
<p>Undoubtedly, there are challenges associated with TCO implementation. With respect to the management of change, staffs must be trained (and rewarded for) overcoming the practice of only evaluating acquisition costs. These organizational changes likely will result in increased training expenses and require ardent support from senior executive leadership. Furthermore, long-term benefits realized by using this method are difficult to capture in an annual budget cycle, necessitating alternate governance protocols to monitor and report multi-year cost savings. For example, a project manager may face the decision between waiting an extra two months for the best-fit condensate pump-motor replacement to arrive or progress with a readily available, lower-cost alternative, knowing the long-term reliability of this component option is lower. Without a governance structure that rewards long-term benefits capture, the project manager may be penalized for selecting the best-fit replacement. There also will be challenges associated, including soft benefits or difficult-to-quantify costs within the analysis. Last, information systems must be in place to capture the data required to quantify indirect costs.</p>
<p>Utilities implementing a structured TCO approach for capital project decision making will be in a position to distinguish themselves from among their peers as effective stewards of allocated capital. The programmatic development and adoption of the TCO approach not only reduces long-term project costs, but also improves communications across departments and provides greater transparency into project cost drivers. These key benefits are achieved through an unwavering commitment to the required culture change and realizing the need for a highly skilled and trained supply-chain staff that communicates with design and work management personnel.</p>
<p> </p>
<h4>Endnotes:</h4>
<p>1. Jason Lehman “Moody’s: Gas, electric IOUs facing near-term borrowing challenges,” <i>SNL Financial LC,</i> Charlottesville, Jan. 16, 2009.</p>
<p>2. “Gartner Total Cost of Ownership,” <i><a href="http://amt.gartner.com/TCO/MoreAboutTCO.htm" target="_blank">http://amt.gartner.com/TCO/MoreAboutTCO.htm</a>.</i></p>
<p>3. Frank A.G. den Butter, Kees A. Linse “Rethinking Procurement in the Era of Globalization,” <i>MIT Sloan Management Review</i>, Fall 2008.</p>
<p>4. Based upon prior project experience.</p>
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<a href="/tags/cost">Cost</a><span class="pur_comma">, </span><a href="/tags/gartner">Gartner</a><span class="pur_comma">, </span><a href="/tags/ious">IOUs</a><span class="pur_comma">, </span><a href="/tags/it">IT</a><span class="pur_comma">, </span><a href="/tags/mit">MIT</a> </div>
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Fri, 01 May 2009 04:00:00 +0000puradmin13724 at http://www.fortnightly.com